Fracturing Process to Enhance Propping Agent Distribution to Maximize Connectivity Between the Formation and the Wellbore

ABSTRACT

A method of treating a subterranean formation may include placing a first treatment fluid into a subterranean formation through an access conduit connecting the subterranean formation to a wellbore at a pressure sufficient to form at least a portion of a fracture network; pumping a second treatment fluid comprising a propping agent into the fracture network such that the propping agent forms a proppant pack in at least a portion of the fracture network; placing a third treatment fluid comprising a secondary diverting agent into the fracture network so as to substantially inhibit fluid flow through at least a portion of the fracture network without substantially inhibiting fluid flow through the access conduit; and placing a fourth treatment fluid comprising a primary diverting agent into the wellbore such that the primary diverting agent substantially inhibits fluid flow through the access conduit.

BACKGROUND

The present invention relates generally to enhancing propping agentdistribution in order to maximize connectivity between a subterraneanformation and a wellbore so as to improve production from a subterraneanformation.

After a wellbore is drilled, it may often be necessary to fracture thesubterranean formation to enhance hydrocarbon production, especially inshale formations that typically have high closure stresses. Access tothe subterranean formation can be achieved by first creating an accessconduit from the wellbore to the subterranean formation. Then, afracturing fluid, called a pad, is introduced at pressures exceedingthose required to maintain matrix flow in the formation permeability tocreate or enhance at least one fracture that propagates from at leastone access conduit. The pad fluid is followed by a fluid comprising apropping agent to prop the fracture open after pressure is reduced. Insome formations like shales, fractures can further branch into smallfractures extending from a primary fracture giving depth and breadth tothe fracture network created in the subterranean formation. As usedherein, a “fracture network” refers to the access conduits, fractures,microfractures, and/or branches, man-made or otherwise, within asubterranean formation that are in fluid communication with thewellbore. The propping agents hold open the fracture network therebymaintaining the ability for fluid to flow through the fracture networkto ultimately be produced at the surface,

Distribution of the propping agents is an important factor to maximizingproduction from the fracture network. Propping agents, like the fluid inwhich they are suspended, follow the path of least resistance, which inpractice is typically into only a small percentage of fractures thathave been created, and most definitely not into an appreciable number ofbranches that extend therefrom. Heterogeneous distribution of proppingagents within a fracture network often yields a production curve withshorter steady state production and steep production decline, shown inFIG. 1 a, i.e., the formation produces hydrocarbon for a shorter amountof time and production decline is very rapid. This is most oftenobserved in shale and other very low permeability formations. Recoveringa well after production decline typically involves refracturing, whichcan be costly and time consuming.

To provide a more uniform distribution of propping agents in the entirefracture network to maximize production potential, some form ofdiversion within or among zones in the subterranean formation may beuseful. For example, a packer or bridge plug may be used between sets ofaccess conduits to divert a treatment fluid between the access conduits.Also, sand may be used as diverting agents to plug or bridge an accessconduit. In another technique, balls, commonly referred to as “perfballs,” may be used to seal off individual access conduits to divertfluid, and consequently propping agents, to other access conduits. Suchtechniques may be only partially successful towards uniform distributionof propping agents, especially in dendritic and shattered fracturenetworks, because they only address the distribution issues at thewellbore, i.e., at the access conduit, not within the highlyinterconnected, multi-branched fracture network.

One of many problems in the use of some or all of the above describedprocedures may be that the means of diverting the treatment fluidrequires an additional step of removing it from the wellbore to allowthe maximum flow of produced hydrocarbon from the subterranean zone intothe wellbore. For example, a bridge plug generally is removed or drilledout at the end of the operation to allow for production. Similarly, sandplugs or bridges are cleaned out for production; sealing balls are oftenrecovered for production, both of which incur additional time andexpenses.

Particulate diverting agents may be difficult to remove completely fromthe subterranean formation, which may cause a residue to remain in thewellbore area following the fracturing operation, which may permanentlyreduce the permeability of the formation. In some cases, difficulty inremoving conventional diverting agents from the formation maypermanently reduce the permeability of the formation by between 5% to40%, and may even cause a 100% permanent reduction in permeability insome instances.

Additionally, when the wellbore to be treated is a highly deviatedwellbore, traditional sand plugs are thought to be ineffective atisolating zones along the highly deviated wellbore because they may failto fully plug the diameter of the wellbore. As used herein, the term“deviated wellbore” refers to a wellbore in which any portion of thewell is in excess of about 55-degrees from a vertical inclination. Asused herein, the term “highly deviated wellbore” refers to a wellborethat is oriented between 75-degrees and 90-degrees off-vertical (wherein90-degrees off-vertical corresponds to a fully horizontal wellbore).That is, the term “highly deviated wellbore” may refer to a portion of awellbore that is anywhere from fully horizontal (90-degreesoff-vertical) to 75-degrees off-vertical.

SUMMARY OF THE INVENTION

The present invention relates generally to enhancing propping agentdistribution in order to maximize connectivity between a subterraneanformation and a wellbore so as to improve production from a subterraneanformation.

In some embodiments, the present invention provides a method thatcomprises: providing a wellbore penetrating a subterranean formation,wherein the subterranean formation is able to support a fracturenetwork; providing at least one access conduit to the subterraneanformation from the wellbore; placing a first treatment fluid into thesubterranean formation through the at least one access conduit at apressure sufficient to form at least a portion of a fracture networkextending from the at least one access conduit; pumping a secondtreatment fluid comprising a propping agent into the fracture networksuch that the propping agent forms a proppant pack in at least a portionof the fracture network; placing a third treatment fluid comprising asecondary diverting agent into the wellbore such that the secondarydiverting agent goes through the access conduit and into at least aportion of the fracture network so as to substantially inhibit fluidflow through at least a portion of the fracture network withoutsubstantially inhibiting fluid flow through the access conduit; andplacing a fourth treatment fluid comprising a primary diverting agentinto the wellbore such that the primary diverting agent substantiallyinhibits fluid flow through the access conduit.

In some embodiments, the present invention provides a method thatcomprises: providing a wellbore penetrating a subterranean formation,wherein the subterranean formation has a closure pressure greater thanabout 500 psi; providing at least one access conduit to the subterraneanformation from the wellbore; placing a first treatment fluid into thesubterranean formation through the at least one access conduit at apressure sufficient to form at least a portion of a fracture networkextending from the at least one access conduit; pumping a secondtreatment fluid comprising a propping agent into the fracture networksuch that the propping agent forms a proppant pack in at least a portionof the fracture network; placing a third treatment fluid comprising asecondary diverting agent into the wellbore such that the secondarydiverting agent goes through the access conduit and into at least aportion of the fracture network so as to substantially inhibit fluidflow through at least a portion of the fracture network withoutsubstantially inhibiting fluid flow through the access conduit; andplacing a fourth treatment fluid comprising a primary diverting agentinto the wellbore such that the primary diverting agent substantiallyinhibits fluid flow through the access conduit.

In some embodiments, the present invention provides a method thatcomprises: providing a wellbore penetrating a subterranean formation,wherein the subterranean formation is able to support a fracture networkand the wellbore has at least one access conduit to the subterraneanformation from the wellbore; placing a first treatment fluid into thesubterranean formation at a pressure sufficient to form at least aportion of a fracture network extending from at least one accessconduit; pumping a second treatment fluid comprising a propping agentinto the fracture network such that the propping agent forms a proppantpack in at least a portion of the fracture network, wherein the proppingagent comprises proppant particulates at least partially coated with aconsolidating agent and at least a portion of degradable particles;placing a third treatment fluid comprising a secondary diverting agentinto the wellbore such that the secondary diverting agent goes throughthe access conduit and into at least a portion of the fracture networkso as to substantially inhibit fluid flow through at least a portion ofthe fracture network without substantially inhibiting fluid flow throughthe access conduit, wherein the secondary diverting agent is at leastpartially degradable; placing a fourth treatment fluid comprising aprimary diverting agent into the wellbore such that the primarydiverting agent substantially inhibits fluid flow through the accessconduit, wherein the primary diverting agent is at least partiallydegradable; and repeating at least one step selected from the groupconsisting of pumping the second treatment fluid, placing the thirdtreatment fluid, placing the fourth treatment fluid, placing the fifthtreatment fluid, and any combination thereof.

The features and advantages of the present invention will be readilyapparent to those skilled in the art upon a reading of the descriptionof the preferred embodiments that follows.

BRIEF DESCRIPTION OF THE DRAWINGS

The following figures are included to illustrate certain aspects of thepresent invention, and should not be viewed as exclusive embodiments.The subject matter disclosed is capable of considerable modification,alteration, and equivalents in form and function, as will occur to thoseskilled in the art and having the benefit of this disclosure.

FIGS. 1 a-b illustrate the production curve of a subterranean formationbased on distribution of propping agents.

FIG. 2 illustrates the placement of elements within a dendritic fracturenetwork.

FIG. 3 illustrates the placement of elements within a shattered fracturenetwork,

FIG. 4 illustrates a nonlimiting example of a fracture network responseto a method of the present invention.

FIG. 5 illustrates a nonlimiting example of wellbore pressure during amethod of the present invention.

DETAILED DESCRIPTION

The present invention relates generally to enhancing propping agentdistribution in order to maximize connectivity between a subterraneanformation and a wellbore so as to improve production from a subterraneanformation.

The methods of the present invention provide for the systematicintroduction of a series of diverting agents that enhances the uniformdistribution of propping agents through a fracture network. In brittleformations, like shale, a fracture network may comprise access conduits,fractures, microfractures, and branches. As used herein, an “accessconduit” refers to a passageway that provides fluid communicationbetween the wellbore and the subterranean formation, which may include,but not be limited to, sliding sleeves, open holes in non-cased areas,hydrajetted holes, holes in the casing, perforations, and the like. Themethods of the present invention provide for treatment fluid andpropping agent diversion in at least each of these fracture networkcomponents. Uniform distribution of propping agents maximizes theconnectivity between the formation and the wellbore, thereby maximizinghydrocarbon production therefrom. Further, the diversion methodsprovided herein better dilate the branches that give depth and breadthto a fracture network. Without being bound by theory, it is believedthat dilated components of a fracture network more readily incorporatepropping agents, which consequently yields more hydrocarbon inproduction operations. These methods may be particularly useful indeviated wellbores that are notorious for heterogeneous distribution ofpropping agents and heterogeneous fracture network dilation.

Uniform distribution of propping agents allows for the use of lessoverall propping agents, thereby reducing the cost of the operation. Asdepicted in the comparison of FIG. 1, uniform distribution of proppingagents (FIG. 1 b) may extend the lifetime of a well by increasing thelength of the steady-state production and reducing the rate ofproduction decline, as compared to heterogeneous propping agentdistribution (FIG. 1 a).

Further advantageously, some embodiments may include some combination ofthe various diverting agents being degradable. Degradable divertingagents decrease, and may eliminate, the need for secondary operations torestore fluid conductivity within the fracture network when productionoperations begin, which consequently reduces the environmental impact ofsubterranean operations. This reduces the cost and time for fracturingoperations.

In some methods of the present invention, any combination of proppingagents, a primary diverting agent, a secondary diverting agent, andoptionally a degradable particle may be introduced via a treatment fluidinto a wellbore penetrating a subterranean formation. In someembodiments, the elements of a propping agent, a primary divertingagent, a secondary diverting agent, and optionally a degradable particlemay be introduced into a wellbore via a single treatment fluidcomprising all of the elements, individual treatment fluids comprising asingle element, a plurality of treatment fluids comprising somecombination of at least two of the elements, and any combinationthereof. As used herein, the term “treatment,” or “treating,” refers toany subterranean operation that uses a fluid in conjunction with adesired function and/or for a desired purpose. The term “treatment,” or“treating,” does not imply any particular action by the fluid.

As used herein, a “diverting agent” refers to any material that can beused to substantially seal off a portion of a subterranean formationthereby substantially reducing, including blocking, fluid flowtherethrough. As used herein, a “primary diverting agent” refers to adiverting agent that substantially inhibits fluid flow through an accessconduit. As used herein, a “secondary diverting agent” refers to adiverting agent that substantially inhibits fluid flow through at leasta portion of the fracture network. Suitable diverting agents maycomprise gels, particles, and/or fibers that are natural or synthetic;degradable or nondegradable; and mixtures thereof. Nonlimiting examplesof suitable diverting agents are included below.

As used herein, “propping agents” refers to any material or formulationthat can be used to hold open at least a portion of a fracture network.As used herein, a “proppant pack” is the collection of propping agentsin a fracture network.

As used herein, a “degradable particle,” and derivatives thereof, refersto any material that can be used in conjunction with a proppant packthat when substantially degraded leaves a void in the proppant pack. Itshould be understood that the term “particulate” or “particle,” andderivatives thereof as used in this disclosure, includes all knownshapes of materials, including substantially spherical materials, low tohigh aspect ratio materials, fibrous materials, polygonal materials(such as cubic materials), and mixtures thereof. As used herein, theterms “degradation” or “degradable” refer to both the two relativelyextreme cases of hydrolytic degradation that the degradable material mayundergo, e.g., heterogeneous (or bulk erosion) and homogeneous (orsurface erosion), and any stage of degradation in between these two.This degradation can be a result of, inter alia, a chemical or thermalreaction, or a reaction induced by radiation. Nonlimiting examples ofdegradable particles are included below.

It should be noted that when “about” is provided at the beginning of anumerical list, “about” modifies each number of the numerical list. Itshould be noted that in some numerical listings of ranges, some lowerlimits listed may be greater than some upper limits listed. One skilledin the art will recognize that the selected subset will require theselection of an upper limit in excess of the selected lower limit.

In some embodiments, at least one access conduit from the wellbore tothe subterranean formation may be created. In some embodiments, at leastone access conduit from the wellbore to the subterranean formation maybe provided. These access conduits may be made by any means or techniqueknown in the art including, but not limited to, hydrajetting; laserinscribing; perforating; not casing at least a portion of the wellbore,and the like. Suitable examples of perforation tools and methods mayinclude, but not be limited to, those disclosed in U.S. Pat. Nos.5,398.760; 5,701,957; 6,435,278; 7,159,660; 7,172,023; 7,225,869;7,303,017; and 7,841,396, the entirety of which are incorporated hereinby reference. Access conduits may be spaced randomly, spacedsubstantially equidistant from each other, clustered in groups (e.g., anaccess conduit cluster), or any combination thereof along the length ofthe wellbore.

In some embodiments, a treatment fluid may be introduced into a wellboreat a pressure sufficient to form at least one fracture extending from atleast one access conduit into a subterranean formation. In someembodiments, the pressure may be sufficient to form at least one branchextending from at least one fracture. In some embodiments, the pressuremay be sufficient to form a fracture network. In some embodiments, thepressure may be sufficient to form at least a portion of a fracturenetwork. In some embodiments, a fracture network may comprise accessconduits, fractures, microfractures, branches, or any combinationthereof including those which are natural and man-made. In someembodiments, a fracture network may be considered a dendritic fracturenetwork, a shattered fracture network, or any combination thereof. FIG.2 illustrates a nonlimiting example of a dendritic fracture networkextending from a wellbore into a subterranean formation. FIG. 3illustrates a nonlimiting example of a shattered fracture networkextending from a wellbore into a subterranean formation. Thesenonlimiting examples illustrate two types of fracture networks extendingfrom a horizontal well. It should be understood that the methodsprovided herein are applicable to wellbores at any angle including, butnot limited to, vertical wells, deviated wells, highly deviated wells,horizontal wells, and hybrid wells comprising sections of anycombination of the aforementioned wells. In some embodiments, asubterranean formation and wellbore may be provided with an existingfracture network.

In some methods of the present invention, any single or combination ofelements including propping agents, a primary diverting agent, asecondary diverting agent, and a degradable particle may be placed via atreatment fluid into a wellbore penetrating a subterranean formation. Itshould be noted that placing may include pumping, introducing, adding,injecting, inserting, and the like.

Some embodiments of the present invention may include the followingsteps:

(a) placing a first treatment fluid into a wellbore at a pressuresufficient to create or enhance at least a portion of a fracturenetwork;

(b) placing a second treatment fluid comprising propping agents into awellbore;

(c) placing a third treatment fluid comprising a secondary divertingagent into the wellbore;

(d) placing a fourth treatment fluid comprising a primary divertingagent into the wellbore; and

(e) optionally placing a fifth treatment fluid comprising a degradableparticulate into the wellbore.

It should be noted that the number modifiers, i.e., first, second,third, fourth, and fifth, do not necessarily indicate an order ofplacement or differences in composition. They are only meant todifferentiate between treatment fluids. In some embodiments, a method oftreating a subterranean formation may comprise either step c or step dlisted above.

As described above and illustrated in FIG. 2, a primary diverting agentmay substantially inhibit fluid flow through an access conduit and/ordivert fluid flow to another access conduit. A secondary diverting agentmay substantially inhibit fluid flow within the fracture network, e.g.,through a fracture and/or a branch so as to divert fluid flow tobranches extending from the fracture. A degradable particle mayincorporate into a proppant pack such that when substantially degraded avoid in the proppant pack is produced.

In some embodiments, the steps provided above may be performed in order.In some embodiments, one or more steps may be performed more than once.In some embodiments, one or more steps may be performed simultaneously.In some embodiments, the steps provided above may be performed in anyorder. Nonlimiting examples of methods of the present invention mayinclude the following:

-   -   (1) a-b-b/c-b/e-b/c/e-b/d-b/c-b/e-b/c-b/e-b/c/e;    -   (2) a/b-c-c/e-b-c-b-d-b-b/c/e-b-b/d-b/c-b; and    -   (3) a/b/e-b/e-b/c-b/e-b-b/e-b/c-b-b/d-b/c/e-b/c,        it should be noted that performing two steps simultaneously,        i.e., b/c, indicates that the second treatment fluid and the        third treatment fluid are one in the same. Other combinations        may also be suitable.

The diversion methods of the present invention may provide for betterdilation of the components of the fracture network, which enhanceshydrocarbon production. By way of nonlimiting example, FIG. 4illustrates the dilation (line thickening) of a fracture network as thesteps of b/e-b/c-b/c-b/d-b/e-b/c are performed on an already fracturedsubterranean formation (propping agents not shown, only dilationprogression).

In some embodiments, the amount of an element within a treatment fluidmay vary during a step. By way of nonlimiting example, the introductionof propping agents in a treatment fluid may be at 30 pounds per gallon(“ppg”) when the step begins then reduce to 10 ppg when the end of thestep is complete. In some embodiments, changing the amount of an elementin a treatment fluid may be an increase or decrease as a stepwisechange, a gradient change, or any combination thereof. In someembodiments where multiple elements are introduced simultaneously, theamount of one or more elements may change during the step.

In some embodiments, the amount of element(s) may stay constant whilethe amount of other additive(s), including those described below, arechanged. In some embodiments, both the amount of element(s) andadditive(s) may change within a step.

In some embodiments, the methods of the present invention optionally maycomprise monitoring the flow of one or more treatment fluids in at leasta portion of the subterranean formation during all or part of a methodof the present invention. Monitoring may, for example, ensure a primaryand/or secondary diverting material are being placed appropriatelywithin the fracture network, determine the presence or absence of aprimary and/or secondary diverting material in the fracture network,and/or determine whether a primary and/or secondary diverting materialactually diverts fluids introduced into the subterranean formation.Monitoring may be accomplished by any technique or combination oftechniques known in the art. In certain embodiments, this may beaccomplished by monitoring the fluid pressure at the surface of awellbore penetrating the subterranean formation where fluids areintroduced. For example, if the fluid pressure at the surface increases,this may indicate that the fluid is being diverted within the fracturenetwork. Additionally, a pressure decrease or substantially steady-statepressure may indicate a portion of the fracture network is dilating.Pressure monitoring techniques may include various logging techniquesand/or computerized fluid tracking techniques known in the art that arecapable of monitoring fluid flow. Examples of commercially availableservices involving surface fluid pressure sensing that may be suitablefor use in the methods of the present invention include those availableunder the tradename EZ-GAUGE™ (surface pressure sensing tools, availablefrom Halliburton Energy Services, Inc., Duncan, Okla.),

It should be noted that fluid pressure changes may not always beobservable at the wellbore surface during fluid diversion and/orfracture network dilation. By way of nonlimiting example, fluiddiversion because of placement of a secondary diverting agent may occurwithout an observable by an increase in fluid pressure at the wellboresurface.

In some embodiments, an element may be introduced into the wellboreafter the wellbore pressure increases and begins to level off. In someembodiments, an element may be introduced into the wellbore duringsubstantially steady-state wellbore pressure. By way of nonlimitingexample, FIG. 5 illustrates two possible operations using methods of thepresent invention. In Scenario 1, propping agents are introduced in aperiodic fashion; while in Scenario 2, the propping agents areintroduced continuously and increased step-wise over time. Atsteady-state wellbore pressure, secondary diverting agent is added intwice followed by introduction of the primary diverting agent. Theprimary diverting agent substantially blocks the flow of fluid throughan access conduit causing wellbore pressure to increase. These steps arerepeated with similar results.

In some embodiments, monitoring the flow of one or more treatment fluidsin at least a portion of the subterranean formation may be accomplished,in part, by using a distributed temperature sensing (DTS) technique.These techniques may involve a series of steps. Generally, a temperaturesensing device (e.g., thermocouples, thermistors, or fiber optic cables)may be placed in a wellbore penetrating a portion of a subterraneanformation, either permanently or retrievably, to record temperature datain the formation and/or the wellbore. In certain applications, a fiberoptic cable may be pre-installed in a casing string before the casingstring is placed in the wellbore. In some applications, it may bedesirable to use an additional apparatus (e.g., coiled tubing) or fluidto place the fiber optic cable in the wellbore. In some embodiments, onemay establish baseline temperature profile for all or part of thesubterranean formation, and then monitor changes in temperature todetermine the flow of fluids in various portions of the subterraneanformation. Various computer software packages may be used to process thetemperature data and/or create visualizations based on that data.Certain DTS techniques that may be suitable for use in the methods ofthe present invention may include commercially-available DTS servicessuch as those known under the tradenames STIMWATCH® (available fromHalliburton Energy Services, Inc., Duncan, Okla.) or SENSA™ (availablefrom Schlumberger Technology Corporation, Sugar Land, Tex.). Certainexamples of DTS techniques that may be suitable for use in the methodsof the present invention also may include those described in U.S. Pat.Nos. 5,028,146; 6,557,630; 6,751,556; 7,055,604; and 7,086,484, theentire disclosures of which are incorporated herein by reference. One ofordinary skill in the art, with the benefit of this disclosure, shouldrecognize whether it is desirable to monitor the flow of one or moretreatment fluids in at least a portion of the subterranean formation aswell as techniques of doing so appropriate for a particular applicationof the present invention based on, inter alia, the characteristics ofvarious portions of the subterranean formation, the types of treatmentfluids present, equipment availability, and other relevant factors.

The methods of the present invention may be used in any subterraneanformation capable of being fractured. Formations where the presentmethods may be most advantageous include, but are not limited to,formations with at least a portion of the formation characterized byvery low permeability; very low formation pore throat size; high closurepressures; high brittleness index; and any combination thereof.

In some embodiments, at least a portion of a subterranean formation mayhave a permeability ranging from a lower limit of about 0.1 nano Darcy(nD), 1 nD, 10 nD, 25 nD, 50 nD, 100 nD, or 500 nD to an upper limit ofabout 10 mD, 1 mD, 500 microD, 100 microD, 10 microD, or 500 nD, andwherein the permeability may range from any lower limit to any upperlimit and encompass any subset therebetween. One method to determine thesubterranean formation permeability includes The American PetroleumInstitute Recommended Practice 40, “Recommended Practices for CoreAnalysis,” Second Edition, February 1998, the entirety of which isincorporated herein by reference,

In some embodiments, at least a portion of a subterranean formation mayhave an average formation pore throat size ranging from a lower limit ofabout 0.005 microns, 0.01 microns, 0.05 microns, 0.1 microns, 0.25microns, or 0.5 microns to an upper limit of about 2.0 microns, 1.5microns, 1.0 microns, or 0.5 microns, and wherein the average formationpore throat size may range from any lower limit to any upper limit andencompass any subset therebetween. One method to determine the porethroat size of a subterranean formation includes the AAPG Bulletin,March 2009, v. 93, no. 3, pages 329-340, the entirety of which isincorporated herein by reference,

In some embodiments, at least a portion of a subterranean formation mayhave a closure pressure greater than about 500 psi to an unlimited upperlimit. While the closure pressure upper limit is believed to beunlimited, formations where the methods of the present invention may beapplicable include formations with a closure pressure ranging from alower limit of about 500 psi, 1000 psi, 1500 psi, or 2500 psi to anupper limit of about 20,000 psi, 15,000 psi, 10,000 psi, 8500 psi, or5000 psi, and wherein the closure pressure may range from any lowerlimit to any upper limit and encompass any subset therebetween. Onemethod to determine the subterranean formation closure pressure includesthe method presented in the Society for Petroleum Engineers paper number60321, the entirety of which is incorporated herein by reference.

In some embodiments, at least a portion of a subterranean formation mayhave a brittleness index ranging from a lower limit of about 5, 10, 20,30, 40, or 50 to an upper limit of about 150, 125, 100, or 75, andwherein the brittleness index may range from any lower limit to anyupper limit and encompass any subset therebetween. Brittleness is acomposite of Poisson's ratio and Young's modulus. One method todetermine the brittleness index of a subterranean formation includes themethod presented in the Society for Petroleum Engineers paper number132990, the entirety of which is incorporated herein by reference.

In certain embodiments, all or part of a wellbore penetrating thesubterranean formation may include casing pipes or strings placed in thewellbore (a “cased hole” or a “partially cased hole”), among otherpurposes, to facilitate production of fluids out of the formation andthrough the wellbore to the surface. In other embodiments, the wellboremay be an “open hole” that has no casing.

In some embodiments, the methods disclosed herein may be used inconjunction with zipper fracture techniques. Zipper fracture techniquesuse pressurized fracture networks in at least one wellbore to direct thefracture network of a second, nearby wellbore. Because the firstfracture network is pressurized and exerting a stress on thesubterranean formation, the second pressure network may extend throughthe path of least resistance, i.e., the portions of the subterraneanformation under less stress. Continuing to hold open portions of thefracture network with propping agent may continue to provide stress onthe subterranean formation even with a reduced fluid pressure therein.Therefore, enhancing the uniform distribution of propping agents througha fracture network may enhance efficacy of a zipper fracture technique.In some embodiments, any of the diversion methods described herein maybe implemented in at least one wellbore to enhance the fracture networkof at least one nearby wellbore.

Suitable diverting agents (primary or secondary) for use in the presentinvention may be any known diverting agent including, but not limitedto, any known lost circulation material, bridging agent, fluid losscontrol agent, diverting agent, plugging agent, or the like suitable foruse in a subterranean formation. Suitable diverting agents may comprisegels, particles, and/or fibers that are natural or synthetic; degradableor nondegradable; and mixtures thereof. Nonlimiting examples ofcommercially available diverting agents include diverting agents in theBIOVERT® series (degradable diverting agents, available from HalliburtonEnergy Services, Inc.) including, but not limited to BIOVERT®NWB (abiomodal, degradable diverting agent, available from Halliburton EnergyServices, Inc.) as a primary diverting agent and BIOVERT®CF (adegradable diverting agent, available from Halliburton Energy Services,Inc.) as a secondary diverting agent.

Primary diverting agents for use in the present invention may compriseparticulates. In some embodiments, particulates of a primary divertingagent may have an average diameter ranging from a lower limit of about0.5 microns, 1 micron, 10 microns, 100 microns, or 500 microns to anupper limit of about 10 mm, 5 mm, 1 mm, 500 microns, or 100 microns, andwherein the average diameter may range from any lower limit to any upperlimit and encompass any subset therebetween. In some embodiments,particulates of a primary diverting agent may have a multi-modaldiameter distribution including bimodal.

Secondary diverting agents for use in the present invention may compriseparticulates. In some embodiments, particulates of a secondary divertingagent may have an average diameter less than about 150 microns. Suitableaverage diameters for particulates of a secondary diverting agent mayrange from a lower limit of about 100 nm, 250 nm, 500 nm, 1 micron, 10microns, or 50 microns to an upper limit of about 150 microns, 100microns, 50 microns, or 10 microns, and wherein the average diameter mayrange from any lower limit to any upper limit and encompass any subsettherebetween. In some embodiments, the secondary diverting agent mayhave an average diameter less than or equal to a proppant particulate ofthe propping agents. In some embodiments, the primary diverting agentmay comprise particulates with a larger average diameter thanparticulates of a secondary diverting agent.

Suitable examples of materials for a diverting agent include, but arenot limited to, sand, shale, ground marble, bauxite, ceramic materials,glass materials, metal pellets, high strength synthetic fibers,cellulose flakes, wood, resins, polymer materials (crosslinked orotherwise), polytetrafluoroethylene materials, nut shell pieces, curedresinous particulates comprising nut shell pieces, seed shell pieces,cured resinous particulates comprising seed shell pieces, fruit pitpieces, cured resinous particulates comprising fruit pit pieces,composite particulates, and any combination thereof. Suitable compositeparticulates may comprise a binder and a filler material whereinsuitable filler materials include silica, alumina, fumed carbon, carbonblack, graphite, mica, titanium dioxide, meta-silicate, calciumsilicate, kaolin, talc, zirconia, boron, fly ash, hollow glassmicrospheres, solid glass, and any combination thereof.

In some embodiments, a diverting agent may be at least partiallydegradable. Nonlimiting examples of suitable degradable materials thatmay be used in the present invention include, but are not limited to,degradable polymers (crosslinked or otherwise), dehydrated compounds,and/or mixtures of the two. Examples of suitable degradable solidparticulates may be found in U.S. Pat. Nos. 7,036,587; 6,896,058;6,323,307; 5,216,050; 4,387,769; 3,912,692; and 2,703,316, the relevantdisclosures of which are incorporated herein by reference. The terms“polymer” or “polymers” as used herein do not imply any particulardegree of polymerization; for instance, oligomers are encompassed withinthis definition. A polymer is considered to be “degradable” herein if itis capable of undergoing an irreversible degradation when used insubterranean applications, e.g., in a wellbore. The term “irreversible”as used herein means that the degradable material should degrade in situ(e,g., within a wellbore) but should not recrystallize or reconsolidatein situ after degradation (e.g., in a wellbore).

Degradable materials may include, but not be limited to, dissolvablematerials, materials that deform or melt upon heating such asthermoplastic materials, hydrolytically degradable materials, materialsdegradable by exposure to radiation, materials reactive to acidicfluids, or any combination thereof. In some embodiments, degradablematerials may be degraded by temperature, presence of moisture, oxygen,microorganisms, enzymes, pH, free radicals, and the like. In someembodiments, degradation may be initiated in a subsequent treatmentfluid introduced into the subterranean formation at some time whendiverting is no longer necessary. In some embodiments, degradation maybe initiated by a delayed-release acid, such as an acid-releasingdegradable material or an encapsulated acid, and this may be included inthe treatment fluid comprising the degradable material so as to reducethe pH of the treatment fluid at a desired time, for example, afterintroduction of the treatment fluid into the subterranean formation.

In choosing the appropriate degradable material, one should consider thedegradation products that will result. Also, these degradation productsshould not adversely affect other operations or components. For example,a boric acid derivative may not be included as a degradable material inthe well drill-in and servicing fluids of the present invention wheresuch fluids use guar as the viscosifier, because boric acid and guar aregenerally incompatible. One of ordinary skill in the art, with thebenefit of this disclosure, will be able to recognize when potentialcomponents of a treatment fluid of the present invention would beincompatible or would produce degradation products that would adverselyaffect other operations or components.

The degradability of a degradable polymer often depends, at least inpart, on its backbone structure. For instance, the presence ofhydrolyzable and/or oxidizable linkages in the backbone often yields amaterial that will degrade as described herein. The rates at which suchpolymers degrade are dependent on the type of repetitive unit,composition, sequence, length, molecular geometry, molecular weight,morphology (e,g., crystallinity, size of spherulites, and orientation),hydrophilicity, hydrophobicity, surface area, and additives. Also, theenvironment to which the polymer is subjected may affect how itdegrades, e.g., temperature, presence of moisture, oxygen,microorganisms, enzymes, pH, and the like.

Suitable examples of degradable polymers for a solid particulate of thepresent invention that may be used include, but are not limited to,polysaccharides such as cellulose; chitin; chitosan; and proteins.Suitable examples of degradable polymers that may be used in accordancewith the present invention include, but are not limited to, thosedescribed in the publication of Advances in Polymer Science, Vol. 157entitled “Degradable Aliphatic Polyesters,” edited by A. C. Albertsson,pages 1-138. Specific examples include homopolymers, random, block,graft, and star- and hyper-branched aliphatic polyesters. Such suitablepolymers may be prepared by polycondensation reactions, ring-openingpolymerizations, free radical polymerizations, anionic polymerizations,carbocationic polymerizations, coordinative ring-openingpolymerizations, as well as by any other suitable process. Examples ofsuitable degradable polymers that may be used in conjunction with themethods of this invention include, but are not limited to, aliphaticpolyesters; poly(lactides); poly(glycolides); poly(ε-caprolactones);poly(hydroxy ester ethers); poly(hydroxybutyrates); poly(anhydrides);polycarbonates; poly(orthoesters); poly(amino acids); poly(ethyleneoxides); poly(phosphazenes); poly(ether esters), polyester amides,polyamides, and copolymers or blends of any of these degradablepolymers, and derivatives of these degradable polymers. The term“copolymer” as used herein is not limited to the combination of twopolymers, but includes any combination of polymers, e.g., terpolymersand the like. As referred to herein, the term “derivative” is definedherein to include any compound that is made from one of the listedcompounds, for example, by replacing one atom in the base compound withanother atom or group of atoms. Of these suitable polymers, aliphaticpolyesters such as poly(lactic acid), poly(anhydrides),poly(orthoesters), and poly(lactide)-co-poly(glycolide) copolymers arepreferred. Poly(lactic acid) is especially preferred. Poly(orthoesters)also may be preferred. Other degradable polymers that are subject tohydrolytic degradation also may be suitable. One's choice may depend onthe particular application and the conditions involved. Other guidelinesto consider include the degradation products that result, the timerequired for the requisite degree of degradation, and the desired resultof the degradation (e.g., voids).

Aliphatic polyesters degrade chemically, inter alia, by hydrolyticcleavage. Hydrolysis can be catalyzed by either acids or bases.Generally, during the hydrolysis, carboxylic end groups may be formedduring chain scission, which may enhance the rate of further hydrolysis.This mechanism is known in the art as “autocatalysis,” and is thought tomake polyester matrices more bulk-eroding,

Suitable aliphatic polyesters have the general formula of repeatingunits shown below:

where n is an integer between 75 and 10,000 and R is selected from thegroup consisting of hydrogen, alkyl, aryl, alkylaryl, acetyl,heteroatoms, and mixtures thereof. In certain embodiments of the presentinvention wherein an aliphatic polyester is used, the aliphaticpolyester may be poly(lactide). Poly(lactide) is synthesized either fromlactic acid by a condensation reaction or, more commonly, byring-opening polymerization of cyclic lactide monomer. Since both lacticacid and lactide can achieve the same repeating unit, the general termpoly(lactic acid) as used herein refers to writ of formula 1 without anylimitation as to how the polymer was made (e.g., from lactides, lacticacid, or oligomers), and without reference to the degree ofpolymerization or level of plasticization.

The lactide monomer exists generally in three different forms: twostereoisomers (L- and D-lactide) and racemic D,L-lactide (meso-lactide).The oligomers of lactic acid and the oligomers of lactide are defined bythe formula:

where m is an integer in the range of from greater than or equal toabout 2 to less than or equal to about 75. In certain embodiments, m maybe an integer in the range of from greater than or equal to about 2 toless than or equal to about 10. These limits may correspond to numberaverage molecular weights below about 5,400 and below about 720,respectively. The chirality of the lactide units provides a means toadjust, inter alia, degradation rates, as well as physical andmechanical properties. Poly(L-lactide), for instance, is asemicrystalline polymer with a relatively slow hydrolysis rate. Thiscould be desirable in applications of the present invention in which aslower degradation of the degradable material is desired.Poly(D,L-lactide) may be a more amorphous polymer with a resultantfaster hydrolysis rate. This may be suitable for other applications inwhich a more rapid degradation may be appropriate. The stereoisomers oflactic acid may be used individually, or may be combined in accordancewith the present invention. Additionally, they may be copolymerizedwith, for example, glycolide or other monomers like ε-caprolactone,1,5-dioxepan-2-one, trimethylene carbonate, or other suitable monomersto obtain polymers with different properties or degradation times.Additionally, the lactic acid stereoisomers can be modified by blendinghigh and low molecular weight polylactide or by blending polylactidewith other polyesters. In embodiments wherein polylactide is used as thedegradable material, certain preferred embodiments employ a mixture ofthe D and L stereoisomers, designed so as to provide a desireddegradation time and/or rate. Examples of suitable sources of degradablematerial are commercially available 6250D™ (poly(lactic acid), availablefrom Cargill Dow) and 5639A™ (poly(lactic acid), available from CargillDow).

Aliphatic polyesters useful in the present invention may be prepared bysubstantially any of the conventionally known manufacturing methods suchas those described in U.S. Pat. Nos. 2,703,316; 3,912,692; 4,387,769;5,216,050; and 6,323,307, the relevant disclosures of which areincorporated herein by reference.

Polyanhydrides are another type of degradable polymer that may besuitable for use in the present invention. Polyanhydride hydrolysisproceeds, inter alia, via free carboxylic acid chain-ends to yieldcarboxylic acids as final degradation products. Their erosion time canbe varied over a broad range of changes in the polymer backbone.Examples of suitable polyanhydrides include poly(adipic anhydride),poly(suberic anhydride), poly(sebacic anhydride), and poly(dodecanedioicanhydride). Other suitable examples include, but are not limited to,poly(maleic anhydride) and poly(benzoic anhydride).

The physical properties of degradable polymers may depend on severalfactors including, but not limited to, the composition of the repeatunits, flexibility of the chain, presence of polar groups, molecularmass, degree of branching, crystallinity, and orientation. For example,short chain branches may reduce the degree of crystallinity of polymerswhile long chain branches may lower the melt viscosity and may impart,inter alia, extensional viscosity with tension-stiffening behavior. Theproperties of the material utilized further may be tailored by blending,and copolymerizing it with another polymer, or by a change in themacromolecular architecture (e.g., hyper-branched polymers, star-shaped,or dendrimers, and the like). The properties of any such suitabledegradable polymers (e.g., hydrophobicity, hydrophilicity, rate ofdegradation, and the like) can be tailored by introducing selectfunctional groups along the polymer chains. For example,poly(phenyllactide) will degrade at about one-fifth of the rate ofracemic poly(lactide) at a pH of 7.4 at 55° C. One of ordinary skill inthe art, with the benefit of this disclosure, will be able to determinethe appropriate functional groups to introduce to the polymer chains toachieve the desired physical properties of the degradable polymers.

Suitable dehydrated compounds for use as solid particulates in thepresent invention may degrade over time as they are rehydrated. Forexample, a particulate solid anhydrous borate material that degradesover time may be suitable for use in the present invention. Specificexamples of particulate solid anhydrous borate materials that may beused include, but are not limited to, anhydrous sodium tetraborate (alsoknown as anhydrous borax) and anhydrous boric acid.

Whichever degradable material is used in the present invention, thedegradable material may have any shape, including, but not limited to,particles having the physical shape of platelets, shavings, flakes,ribbons, rods, strips, spheroids, toroids, pellets, tablets, or anyother physical shape. In certain embodiments of the present invention,the degradable material used may comprise a mixture of fibers andspherical particles. One of ordinary skill in the art, with the benefitof this disclosure, will recognize the specific degradable material thatmay be used in accordance with the present invention, and the preferredsize and shape for a given application.

In choosing the appropriate degradable material, one should consider thedegradation products that will result, and choose a degradable materialthat will not yield degradation products that would adversely affectother operations or components utilized in that particular application.The choice of degradable material also may depend, at least in part, onthe conditions of the well (e.g., wellbore temperature). For instance,lactides have been found to be suitable for lower temperature wells,including those within the range of 60° F. to 150° F., and polylactideshave been found to be suitable for wellbore temperatures above thisrange.

In certain embodiments, the degradation of the degradable material couldresult in a final degradation product having the potential to affect thepH of the self-degrading cement compositions utilized in the methods ofthe present invention. For example, in certain embodiments wherein thedegradable material is poly(lactic acid), the degradation of thepoly(lactic acid) to produce lactic acid may alter the pH of theself-degrading cement composition. In certain embodiments, a buffercompound may be included within the self-degrading cement compositionsutilized in the methods of the present invention in an amount sufficientto neutralize the final degradation product. Examples of suitable buffercompounds include, but are not limited to, calcium carbonate, magnesiumoxide, ammonium acetate, and the like. One of ordinary skill in the art,with the benefit of this disclosure, will be able to identify the propertype and concentration of a buffer compound to include in theself-degrading cement composition for a particular application. Anexample of a suitable buffer compound comprises commercially availableBA20™ (ammonium acetate, available from Halliburton Energy Services,Inc.).

In some embodiments, a diverting agent may be a gel. In someembodiments, the gel may be a crosslinked gel. Examples of gel divertingagents may include, but not be limited to, fluids with highconcentration of gels such as xanthan. Examples of crosslinked gels thatcan be used as the diverting agent include, but are not limited to, highconcentration gels such as DELTA FRAC™ fluids (high viscosity borategel, available from Halliburton Energy Services, Inc.), K-MAX™ fluids(crosslinkable hydroxyethyl cellulose, available from Halliburton EnergyServices, Inc.), and K-MAX-PLUS™ fluids (crosslinkable hydroxyethylcellulose, available from Halliburton Energy Services, Inc.). Gels mayalso be used by mixing the crosslinked gels with delayed chemicalbreakers, encapsulated chemical breakers, which will later reduce theviscosity, or with a material such as PLA (poly-lactic acid) beads,which although being a solid material, with time decomposes into acid,which will liquefy the K-MAX™ fluids or other crosslinked gels.

The gel diverting agents suitable for use in the present invention maycomprise any substance (e.g., a polymeric material) capable ofincreasing the viscosity of the treatment fluid. In certain embodiments,the gelling agent may comprise one or more polymers that have at leasttwo molecules that are capable of forming a crosslink in a crosslinkingreaction in the presence of a crosslinking agent, and/or polymers thathave at least two molecules that are so crosslinked (i.e., a crosslinkedgelling agent). The gel diverting agents may be naturally-occurring geldiverting agents, synthetic gel diverting agents, or a combinationthereof. The gel diverting agents also may be cationic, anionic,amphoteric, or a combination thereof. Suitable gel diverting agentsinclude, but are not limited to, polysaccharides, biopolymers, and/orderivatives thereof that contain one or more of these monosaccharideunits: galactose, mannose, glucoside, glucose, xylose, arabinose,fructose, glucuronic acid, or pyranosyl sulfate. Examples of suitablepolysaccharides include, but are not limited to, guar gums (e.g.,hydroxyethyl guar, hydroxypropyl guar, carboxymethyl guar,carboxymethylhydroxyethyl guar, and carboxymethylhydroxypropyl guar(“CMHPG”)), cellulose derivatives (e.g., hydroxyethyl cellulose,carboxyethylcellulose, carboxymethylcellulose, andcarboxymethylhydroxyethylcellulose), xanthan, scleroglucan, diutan, andcombinations thereof. In certain embodiments, the gelling agentscomprise an organic carboxylated polymer, such as CMHPG.

Suitable synthetic polymers for use as gel diverting agents include, butare not limited to, 2,2′-azobis(2,4-dimethyl valeronitrile),2,2′-azobis(2,4-dimethyl-4-methoxy valeronitrile), polymers andcopolymers of acrylamide ethyltrimethyl ammonium chloride, acrylamide,acrylamido-and methacrylamido-alkyl trialkyl ammonium salts,acrylamidomethylpropane sulfonic acid, acrylamidopropyl trimethylammonium chloride, acrylic acid, dimethylaminoethyl methacrylamide,dimethylaminoethyl methacrylate, dimethylaminopropyl methacrylamide,dimethylaminopropylmethacrylamide, dimethyldiallylammonium chloride,dimethylethyl acrylate, fumaramide, methacrylamide, methacrylamidopropyltrimethyl ammonium chloride,methacrylamidopropyldimethyl-n-dodecylammonium chloride,methacrylamidopropyldimethyl-n-octylammonium chloride,methacrylamidopropyltrimethylammonium chloride, methacryloylalkyltrialkyl ammonium salts, methacryloylethyl trimethyl ammonium chloride,methacrylylamidopropyldimethylcetylammonium chloride,N-(3-sulfopropyl)-N-methacrylamidopropyl-N,N-dimethyl ammonium betaine,N,N-dimethylacrylamide, N-methylacrylamide,nonylphenoxypoly(ethyleneoxy)ethylmethacrylate, partially hydrolyzedpolyacrylamide, poly 2-amino-2-methyl propane sulfonic acid, polyvinylalcohol, sodium 2-acrylamido-2-methylpropane sulfonate, quaternizeddimethylaminoethylacrylate, guaternized dimethylaminoethylmethacrylate,and derivatives and combinations thereof. In certain embodiments, thegelling agent comprises anacrylamide/2-(methacryloyloxy)ethyltrimethylammonium methyl sulfatecopolymer. In certain embodiments, the gelling agent may comprise anacrylamide/2-(methacryloyloxy)ethyltrimethylammonium chloride copolymer.In certain embodiments, the gelling agent may comprise a derivatizedcellulose that comprises cellulose grafted with an allyl or a vinylmonomer, such as those disclosed in U.S. Pat. Nos. 4,982,793; 5,067,565;and 5,122,549, the entire disclosures of which are incorporated hereinby reference.

Additionally, polymers and copolymers that comprise one or morefunctional groups (e.g., hydroxyl, cis-hydroxyl, carboxylic acids,derivatives of carboxylic acids, sulfate, sulfonate, phosphate,phosphonate, amino, or amide groups) may be used as gel divertingagents.

In those embodiments of the present invention where it is desirable tocrosslink the gel diverting agents in situ, the treatment fluidcomprising the gel diverting agents and/or a subsequent treatment fluidmay comprise one or more crosslinking agents. The crosslinking agentsmay comprise a borate ion, a metal ion, or similar component that iscapable of crosslinking at least two molecules of the gelling agent.Examples of suitable crosslinking agents include, but are not limitedto, borate ions, magnesium ions, zirconium IV ions, titanium IV ions,aluminum ions, antimony ions, chromium ions, iron ions, copper ions,magnesium ions, and zinc ions. These ions may be provided by providingany compound that is capable of producing one or more of these ions.Examples of such compounds include, but are not limited to, ferricchloride, boric acid, disodium octaborate tetrahydrate, sodium diborate,pentaborates, ulexite, colemanite, magnesium oxide, zirconium lactate,zirconium triethanol amine, zirconium lactate triethanolamine, zirconiumcarbonate, zirconium acetylacetonate, zirconium malate, zirconiumcitrate, zirconium diisopropylamine lactate, zirconium glycolate,zirconium triethanol amine glycolate, zirconium lactate glycolate,titanium lactate, titanium malate, titanium citrate, titanium ammoniumlactate, titanium triethanolamine, and titanium acetylacetonate,aluminum lactate, aluminum citrate, antimony compounds, chromiumcompounds, iron compounds, copper compounds, zinc compounds, andcombinations thereof. In certain embodiments of the present invention,the crosslinking agent may be formulated to remain inactive until it is“activated” by, among other things, certain conditions in the fluid(e.g., pH, temperature, etc.) and/or interaction with some othersubstance. In some embodiments, the activation of the crosslinking agentmay be delayed by encapsulation with a coating (e.g., a porous coatingthrough which the crosslinking agent may diffuse slowly, or a degradablecoating that degrades downhole) that delays the release of thecrosslinking agent until a desired time or place. The choice of aparticular crosslinking agent may be governed by several considerationsthat should be recognized by one skilled in the art, including, but notlimited to, the following: the type of gelling agent included, themolecular weight of the gel diverting agents, the conditions in thesubterranean formation being treated, the safety handling requirements,the pH of the treatment fluid, temperature, and/or the desired delay forthe crosslinking agent to crosslink the gel diverting agents,

Examples of suitable degradable gel diverting agents may be“stimuli-degradable” and can be found in U.S. Pat. No. 7,306,040, therelevant disclosure of which is incorporated herein by reference.Stimuli that may lead to the degradation of stimuli-degradable geldiverting agents include any change in the condition or properties ofthe gel including, but not limited to, a change in pH (e.g., caused bythe buffering action of the rock or the decomposition of materials thatrelease chemicals such as acids) or a change in the temperature (e.g.,caused by the contact of the fluid with the rock formation).

To form stimuli-degradable gel diverting agents, degradable crosslinkersmay be used to crosslink gelling agents comprising “ethylenicallyunsaturated monomers.” Suitable gelling agents for stimuli-degradablegel diverting agents include, but are not limited to, ionizable monomers(such as 1-N,N-diethylaminoethylmethacrylate); diallyldimethylammoniumchloride; 2-acrylamido-2-methyl propane sulfonate; acrylic add; allylicmonomers (such as di-allyl phthalate; di-allyl maleate; allyl diglycolcarbonate; and the like); vinyl formate; vinyl acetate; vinylpropionate; vinyl butyrate; crotonic acid; itaconic acid acrylamide;methacrylamide; methacrylonitrile; acrolein; methyl vinyl ether; ethylvinyl ether; vinyl ketone; ethyl vinyl ketone; allyl acetate; allylpropionate; diethyl maleate; any derivative thereof; and any combinationthereof.

In some embodiments, the degradable crosslinker for use instimuli-degradable gel diverting agents may contain a degradablegroup(s) including, but not limited to, esters, phosphate esters,amides, acetals, ketals, orthoesters, carbonates, anhydrides, silylethers, alkene oxides, ethers, imines, ether esters, ester amides, esterurethanes, carbonate urethanes, amino acids, any derivative thereof, orany combination thereof. The choice of the degradable group may bedetermined by pH and temperature, the details of which are available inknown literature sources. The unsaturated terminal groups may includesubstituted or unsubstituted ethylenically unsaturated groups, vinylgroups, allyl groups, acryl groups, or acryloyl groups, which arecapable of undergoing polymerization with the above-mentioned gellingagents to form crosslinked gel diverting agents. Suitable degradablecrosslinkers for stimuli-degradable gel diverting agents include, butare not limited to, unsaturated esters such as diacrylates,dimethacrylates, and dibutyl acrylates; acrylamides; ethers such asdivinyl ethers; and combinations thereof. Specific examples include, butare not limited to, poly(ethylene glycol) diacrylate; polyethyleneglycoldimethacrylate; polyethyleneglycol divinyl ether; polyethylene glycoldivinylamide; polypropylene glycol diglycidyl ether; polypropyleneglycol diacrylate; poly(propylene glycol dimethacrylate); bisacrylamide;and combinations thereof. In one embodiment, a stimuli-degradablecrosslinking agent comprises one or more degradable crosslink and twovinyl groups. Some embodiments of these crosslinking agents aresensitive to changes in pH, such as ortho ester-based embodiments,acetal-based embodiments, ketal-based embodiments, and silicon-basedembodiments. Generally speaking, at room temperature, the orthoester-based embodiments should be stable at pHs of above 10, and shoulddegrade at a pH below about 9; the acetal-based embodiments should bestable at pHs above about 8 and should degrade at pH below about 6; theketal-based embodiments should be stable at pHs of about 7 and shoulddegrade at a pH below 7; and the silicon-based embodiments should bestable at pHs above about 7 and should degrade faster in acidic media.Thus, under moderately acidic conditions (pH of around 3), the relativestability of these groups should decrease in the following order:amides>ketals>orthoester. At higher wellbore temperatures, the morestable crosslinking groups contain amides or ethers and would bepreferred over other choices including esters, acetals, and ketals.

The gel diverting agents may be present in the treatment fluids usefulin the methods of the present invention in an amount sufficient toprovide the desired viscosity. In some embodiments, the gel divertingagents may be present in an amount in the range of from a lower limit ofabout 0.1%, 0.15%, 0.25%, 0.5%, 1%, 5%, or 10% by weight of thetreatment fluid to an upper limit of about 40%, 30%, 25%, or 10% byweight of the treatment fluid, and wherein the amount may range from anylower limit to any upper limit and encompass any subset therebetween.

When included, suitable crosslinking agents may be present in thetreatment fluids useful in the methods of the present invention in anamount sufficient to provide the desired degree of crosslinking betweenmolecules of the gel diverting agents. In certain embodiments, thecrosslinking agent may be present in the first treatment fluids and/orsecond treatment fluids of the present invention in an amount in therange of from about 0.005% to about 1% by weight of the treatment fluid.In certain embodiments, the crosslinking agent may be present in thetreatment fluids of the present invention in an amount in the range offrom about 0.05% to about 1% by weight of the first treatment fluidand/or the second treatment fluid. One of ordinary skill in the art,with the benefit of this disclosure, will recognize the appropriateamount of crosslinking agent to include in a treatment fluid of thepresent invention based on, among other things, the temperatureconditions of a particular application, the type of gel diverting agentsused, the molecular weight of the gel diverting agents, the desireddegree of viscosification, and/or the pH of the treatment fluid.

It should be noted that any derivative, any mixture, and any combinationof the diverting agents described herein may be used as primarydiverting agents or secondary diverting agents. Further, a primarydiverting agent or a secondary diverting agent may be a hybrid of two ormore diverting agents described herein.

In some embodiments, treatment fluids comprising gel diverting agentsmay include internal gel breakers such as enzyme, oxidizing, acidbuffer, or delayed gel breakers. The gel breakers may cause the geldiverting agents of the present invention to revert to thin fluids thatcan be produced back to the surface, for example, after they havediverted fluid within a fracture network. In some embodiments, the gelbreaker may be formulated to remain inactive until it is “activated” by,among other things, certain conditions in the fluid (e,g., pH,temperature, etc.) and/or interaction with some other substance. In someembodiments, the gel breaker may be delayed by encapsulation with acoating (e.g., porous coatings through which the breaker may diffuseslowly, or a degradable coating that degrades downhole) that delays therelease of the gel breaker. In other embodiments the gel breaker may bea degradable material (e.g., polylactic acid or polygylcolic acid) thatreleases an acid or alcohol in the present of an aqueous liquid. Incertain embodiments, the gel breaker used may be present in a treatmentfluid in an amount in the range of from about 0.0001% to about 200% byweight of the gelling agent. One of ordinary skill in the art, with thebenefit of this disclosure, should recognize the type and amount of agel breaker to include in certain treatment fluids of the presentinvention based on, among other factors, the desired amount of delaytime before the gel breaks, the type of gel diverting agents used, thetemperature conditions of a particular application, the desired rate anddegree of viscosity reduction, and/or the pH of the treatment fluid,

Degradable particulates for use in the present invention may have anaverage diameter about the diameter of the propping agents including,but not limited to, about 2 mesh to about 400 mesh on the U.S. SieveSeries. However, in certain circumstances, other mean particulate sizesmay be desired and will be entirely suitable for practice of the presentinvention.

Degradable particles may comprise any materials suitable for use in asubterranean formation provided at least a portion of the degradableparticulate is degradable. Suitable compositions include those disclosedherein for use in diverting agents including any derivative, anymixture, and any combination thereof. A nonlimiting example of acommercially available degradable particulate includes degradableparticulates in the BIOVOID® series (degradable particles, availablefrom Halliburton Energy Services, Inc.). Degradable particles may beself-degradable, stimuli-degradable, or any combination thereof. In someembodiments, a treatment fluid may be introduced into the wellbore withan additive designed to initiate, accelerate, slow, or delay degradationof the degradable particles, in some embodiments, such an additive maybe introduced simultaneously with the degradable particulates.

In certain embodiments, propping agents for use in the present inventionmay comprise a plurality of proppant particulates. Proppant particulatessuitable for use in the present invention may comprise any materialsuitable for use in subterranean operations. Suitable materials forthese proppant particulates include, but are not limited to, sand,bauxite, ceramic materials, glass materials, polymer materials,polytetrafluoroethylene materials, nut shell pieces, cured resinousparticulates comprising nut shell pieces, seed shell pieces, curedresinous particulates comprising seed shell pieces, fruit pit pieces,cured resinous particulates comprising fruit pit pieces, wood, compositeparticulates, and combinations thereof. Suitable composite particulatesmay comprise a binder and a filler material wherein suitable fillermaterials include silica, alumina, fumed carbon, carbon black, graphite,mica, titanium dioxide, meta-silicate, calcium silicate, kaolin, talc,zirconia, boron, fly ash, hollow glass microspheres, solid glass, andcombinations thereof. The mean particulate size generally may range fromabout 2 mesh to about 400 mesh on the U.S. Sieve Series; however, incertain circumstances, other mean particulate sizes may be desired andwill be entirely suitable for practice of the present invention. Inparticular embodiments, preferred mean particulates size distributionranges are one or more of 6/12, 8/16, 12/20, 16/30, 20/40, 30/50, 40/60,40/70, or 50/70 mesh. A proppant particle may be any known shape ofmaterial, including substantially spherical materials, fibrousmaterials, polygonal materials (such as cubic materials), andcombinations thereof. Moreover, fibrous materials, that may or may notbe used to bear the pressure of a dosed fracture, may be included incertain embodiments of the present invention. In certain embodiments,the proppant particulates may be present in a treatment fluid for use inthe present invention in an amount in the range of from about 0.1 poundsper gallon (“ppg”) to about 30 ppg by volume of the treatment fluid.

In some embodiments, a primary diverting agent, a secondary divertingagent, a degradable particulate, a proppant particulate, or anycombination thereof may be coated with a consolidating agent. As usedherein, the term “coating,” and the like, does not imply any particulardegree of coating on the particulate. In particular, the terms “coat” or“coating” do not imply 100% coverage by the coating on the particulate.In some embodiments, a primary diverting agent, a secondary divertingagent, a degradable particulate, a proppant particulate, or anycombination thereof may be coated with a consolidating agent prior tointroduction into a wellbore, after introduction into a wellbore,simultaneous to introduction into a wellbore, or any combinationthereof. In some embodiments, a coating, including degree of coating,may be used to control the rate of degradation of a primary divertingagent, a secondary diverting agent, a degradable particulate, a proppantparticulate, or any combination thereof.

Consolidating agents suitable for use in the methods of the presentinvention generally comprise any compound that is capable of minimizingparticulate migration. Nonlimiting examples of consolidating agentsinclude SANDWEDGE® (an adhesive substance, available from HalliburtonEnergy Services, Inc.) and EXPEDITE® (a two-component resin system,available from Halliburton Energy Services, Inc.). In some embodiments,the consolidating agent may comprise a consolidating agent selected fromthe group consisting of: non-aqueous tackifying agents; aqueoustackifying agents; resins; silyl-modified polyamide compounds;crosslinkable aqueous polymer compositions; and consolidating agentemulsions. Mixtures, combinations, and/or derivatives of these also maybe suitable. The type and amount of consolidating agent included in aparticular method of the present invention may depend upon, among otherfactors, the composition and/or temperature of the subterraneanformation, the chemical composition of formation fluids, the flow rateof fluids present in the formation, the effective porosity and/orpermeability of the subterranean formation, pore throat size anddistribution, and the like. Furthermore, the concentration of theconsolidating agent can be varied, inter alia, to either enhancebridging to provide for a more rapid coating of the consolidating agentor to minimize bridging to allow deeper penetration into thesubterranean formation. It is within the ability of one skilled in theart, with the benefit of this disclosure, to determine the type andamount of consolidating agent to include in the methods of the presentinvention to achieve the desired results.

In some embodiments, the consolidating agent may comprise aconsolidating agent emulsion that comprises an aqueous fluid, anemulsifying agent, and a consolidating agent. The consolidating agent insuitable emulsions may be either a non-aqueous tackifying agent or aresin. These consolidating agent emulsions have an aqueous externalphase and organic-based internal phase. The term “emulsion” and anyderivatives thereof as used herein refers to a combination of two ormore immiscible phases and includes, but is not limited to, dispersionsand suspensions.

Suitable consolidating agent emulsions comprise an aqueous externalphase comprising an aqueous fluid. Suitable aqueous fluids that may beused in the consolidating agent emulsions of the present inventioninclude freshwater, salt water, brine, seawater, or any other aqueousfluid that, preferably, does not adversely react with the othercomponents used in accordance with this invention or with thesubterranean formation. One should note, however, that if long-termstability of the emulsion is desired, a more suitable aqueous fluid maybe one that is substantially free of salts. It is within the ability ofone skilled in the art, with the benefit of this disclosure, todetermine if and how much salt may be tolerated in the consolidatingagent emulsions of the present invention before it becomes problematicfor the stability of the emulsion. The aqueous fluid may be present inthe consolidating agent emulsions in an amount in the range of about 20%to 99.9% by weight of the consolidating agent emulsion composition. Insome embodiments, the aqueous fluid may be present in the consolidatingagent emulsions in an amount in the range of about 60% to 99.9% byweight of the consolidating agent emulsion composition. In someembodiments, the aqueous fluid may be present in the consolidating agentemulsions in an amount in the range of about 95% to 99.9% by weight ofthe consolidating agent emulsion composition.

The consolidating agent in the emulsion may be either a non-aqueoustackifying agent or a resin. The consolidating agents may be present ina consolidating agent emulsion in an amount in the range of about 0.1%to about 80% by weight of the consolidating agent emulsion composition.In some embodiments, the consolidating agent may be present in aconsolidating agent emulsion in an amount in the range of about 0,1% toabout 40% by weight of the composition. In some embodiments, theconsolidating agent may be present in a consolidating agent emulsion inan amount in the range of about 0.1% to about 5% by weight of thecomposition.

As previously stated, the consolidating agent emulsions comprise anemulsifying agent. Examples of suitable emulsifying agents may includesurfactants, proteins, hydrolyzed proteins, lipids, glycolipids, andnanosized particulates, including, but not limited to, fumed silica.Combinations of these may be suitable as well.

In some embodiments of the present invention, the consolidating agentmay comprise a non-aqueous tackifying agent. A particularly preferredgroup of non-aqueous tackifying agents comprises polyamides that areliquids or in solution at the temperature of the subterranean formationsuch that they are, by themselves, non-hardening when introduced intothe subterranean formation. A particularly preferred product is acondensation reaction product comprised of a commercially availablepolyacid and a polyamine. Such commercial products include compoundssuch as combinations of dibasic acids containing some trimer and higheroligomers and also small amounts of monomer acids that are reacted withpolyamines. Other polyacids include trimer acids, synthetic acidsproduced from fatty acids, maleic anhydride, acrylic acid, and the like.Combinations of these may be suitable as well.

Additional compounds which may be used as non-aqueous tackifying agentsinclude liquids and solutions of, for example, polyesters,polycarbonates, silyl-modified polyamide compounds, polycarbamates,urethanes, natural resins such as shellac, and the like. Combinations ofthese may be suitable as well.

Other suitable non-aqueous tackifying agents are described in U.S. Pat.Nos. 5,853,048 and 5,833,000, and U.S. Patent Publication Numbers2007/0131425 and 2007/0131422, the relevant disclosures of which areherein incorporated by reference.

Non-aqueous tackifying agents suitable for use in the present inventionmay either be used such that they form a non-hardening coating on asurface or they may be combined with a multifunctional material capableof reacting with the non-aqueous tackifying agent to form a hardenedcoating. A “hardened coating” as used herein means that the reaction ofthe tackifying compound with the multifunctional material should resultin a substantially non-flowable reaction product that exhibits a highercompressive strength in a consolidated agglomerate than the tackifyingcompound alone with the particulates. In this instance, the non-aqueoustackifying agent may function similarly to a hardenable resin.

Multifunctional materials suitable for use in the present inventioninclude, but are not limited to, aldehydes; dialdehydes such asglutaraldehyde; hemiacetals or aldehyde releasing compounds; diacidhalides; dihalides such as dichlorides and dibromides; polyacidanhydrides; epoxides; furfuraldehyde; aldehyde condensates; andsilyl-modified polyamide compounds; and the like; and combinationsthereof. Suitable silyl-modified polyamide compounds that may be used inthe present invention are those that are substantially self-hardeningcompositions capable of at least partially adhering to a surface or to aparticulate in the unhardened state, and that are further capable ofself-hardening themselves to a substantially non-tacky state to whichindividual particulates such as formation fines will not adhere to, forexample, in formation or proppant pack pore throats. Such silyl-modifiedpolyamides may be based, for example, on the reaction product of asilating compound with a polyamide or a combination of polyamides. Thepolyamide or combination of polyamides may be one or more polyamideintermediate compounds obtained, for example, from the reaction of apolyacid (e.g., diacid or higher) with a polyamine (e.g., diamine orhigher) to form a polyamide polymer with the elimination of water.

In some embodiments of the present invention, the multifunctionalmaterial may be mixed with the tackifying compound in an amount of about0.01% to about 50% by weight of the tackifying compound to effectformation of the reaction product. In other embodiments, themultifunctional material is present in an amount of about 0.5% to about1% by weight of the tackifying compound. Suitable multifunctionalmaterials are described in U.S. Pat. No. 5,839,510, the entiredisclosure of which is herein incorporated by reference.

Aqueous tackifying agents suitable for use in the present invention areusually not generally significantly tacky when placed onto aparticulate, but are capable of being “activated” (e.g., destabilized,coalesced and/or reacted) to transform the compound into a sticky,tackifying compound at a desirable time. Such activation may occurbefore, during, or after the aqueous tackifier agent is placed in thesubterranean formation. In some embodiments, a pretreatment may be firstcontacted with the surface of a particulate to prepare it to be coatedwith an aqueous tackifier agent. Suitable aqueous tackifying agents aregenerally charged polymers that comprise compounds that, when in anaqueous solvent or solution, will form a non-hardening coating (byitself or with an activator) and, when placed on a particulate, willincrease the continuous critical resuspension velocity of theparticulate when contacted by a stream of water. The aqueous tackifieragent may enhance the grain-to-grain contact between the individualparticulates within the formation (be they diverting agents, proppantparticulates, formation fines, or other particulates), helping bringabout the consolidation of the particulates into a cohesive, flexible,and permeable mass.

Suitable aqueous tackifying agents include any polymer that can bind,coagulate, or flocculate a particulate. Also, polymers that function aspressure-sensitive adhesives may be suitable. Examples of aqueoustackifying agents suitable for use in the present invention include, butare not limited to: acrylic acid polymers; acrylic acid ester polymers;acrylic acid derivative polymers; acrylic acid homopolymers; acrylicacid ester homopolymers (such as poly(methyl acrylate), poly(butylacrylate), and poly(2-ethylhexyl acrylate)); acrylic acid esterco-polymers; methacrylic acid derivative polymers; methacrylic acidhomopolymers; methacrylic acid ester homopolymers (such as poly(methylmethacrylate), poly(butyl methacrylate), and poly(2-ethylhexylmethacrylate)); acrylamido-methyl-propane sulfonate polymers;acrylamido-methyl-propane sulfonate derivative polymers;acrylamido-methyl-propane sulfonate co-polymers; and acrylicacid/acrylamido-methyl-propane sulfonate co-polymers; derivativesthereof, and combinations thereof. Methods of determining suitableaqueous tackifying agents and additional disclosure on aqueoustackifying agents can be found in U.S. Patent Publication Numbers2005/0277554 and 2005/0274517, the entire disclosures of which arehereby incorporated by reference.

Some suitable tackifying agents are described in U.S. Pat. No.5,249,627, the entire disclosure of which is incorporated herein byreference, which discloses aqueous tackifying agents that comprise atleast one member selected from the group consisting of benzyl cocodi-(hydroxyethyl) quaternary amine, p-T-amyl-phenol condensed withformaldehyde, and a copolymer comprising from about 80% to about 100%C1-30 alkylmethacrylate monomers and from about 0% to about 20%hydrophilic monomers. In some embodiments, the aqueous tackifying agentmay comprise a copolymer that comprises from about 90% to about 99.5%2-ethylhexylacrylate and from about 0.5% to about 10% acrylic acid.Suitable hydrophillic monomers may be any monomer that will providepolar oxygen-containing or nitrogen-containing groups. Suitablehydrophillic monomers include dialkyl amino alkyl(meth)acrylates andtheir quaternary addition and acid salts, acrylamide, N-(dialkyl aminoalkyl)acrylamide, methacrylamides and their quaternary addition and acidsalts, hydroxy alkyl(meth)acrylates, unsaturated carboxylic acids suchas methacrylic acid or acrylic acid, hydroxyethyl acrylate, acrylamide,and the like. Combinations of these may be suitable as well. Thesecopolymers can be made by any suitable emulsion polymerizationtechnique. Methods of producing these copolymers are disclosed, forexample, in U.S. Pat. No. 4,670,501, the entire disclosure of which isincorporated herein by reference,

In some embodiments of the present invention, the consolidating agentmay comprise a resin. The term “resin” as used herein refers to any ofnumerous physically similar polymerized synthetics or chemicallymodified natural resins including thermoplastic materials andthermosetting materials. Resins that may be suitable for use in thepresent invention may include substantially all resins known and used inthe art.

One type of resin suitable for use in the methods of the presentinvention is a two-component epoxy-based resin comprising a liquidhardenable resin component and a liquid hardening agent component. Theliquid hardenable resin component comprises a hardenable resin and anoptional solvent. The solvent may be added to the resin to reduce itsviscosity for ease of handling, mixing and transferring. It is withinthe ability of one skilled in the art, with the benefit of thisdisclosure, to determine if and how much solvent may be needed toachieve a viscosity suitable to the subterranean conditions. Factorsthat may affect this decision include geographic location of the well,the surrounding weather conditions, and the desired long-term stabilityof the consolidating agent. An alternate way to reduce the viscosity ofthe hardenable resin is to heat it. The second component is the liquidhardening agent component, which comprises a hardening agent, anoptional silane coupling agent, a surfactant, an optional hydrolyzableester for, among other things, breaking gelled fracturing fluid films onparticulates, and an optional liquid carrier fluid for, among otherthings, reducing the viscosity of the hardening agent component.

Examples of hardenable resins that can be used in the liquid hardenableresin component include, but are not limited to, organic resins such asbisphenol A diglycidyl ether resins, butoxymethyl butyl glycidyl etherresins, bisphenol A-epichlorohydrin resins, bisphenol F resins,polyepoxide resins, novolak resins, polyester resins, phenol-aldehyderesins, urea-aldehyde resins, furan resins, urethane resins, glycidylether resins, other epoxide resins, and combinations thereof. In someembodiments, the hardenable resin may comprise a urethane resin.Examples of suitable urethane resins may comprise a polyisocyanatecomponent and a polyhydroxy component. Examples of suitable hardenableresins, including urethane resins, that may be suitable for use in themethods of the present invention include those described in U.S. Pat.Nos. 4,585,064; 6,582,819; 6,677,426; and 7,153,575, the entiredisclosures of which are herein incorporated by reference.

The hardenable resin may be included in the liquid hardenable resincomponent in an amount in the range of about 5% to about 100% by weightof the liquid hardenable resin component. It is within the ability ofone skilled in the art, with the benefit of this disclosure, todetermine how much of the liquid hardenable resin component may beneeded to achieve the desired results. Factors that may affect thisdecision include which type of liquid hardenable resin component andliquid hardening agent component are used.

Any solvent that is compatible with the hardenable resin and achievesthe desired viscosity effect may be suitable for use in the liquidhardenable resin component. Suitable solvents may include butyl lactate,dipropylene glycol methyl ether, dipropylene glycol dimethyl ether,dimethyl formamide, diethyleneglycol methyl ether, ethyleneglycol butylether, diethyleneglycol butyl ether, propylene carbonate, methanol,butyl alcohol, d'limonene, fatty acid methyl esters, and butylglycidylether, and combinations thereof. Other preferred solvents may includeaqueous dissolvable solvents such as methanol, isopropanol, butanol, andglycol ether solvents, and combinations thereof. Suitable glycol ethersolvents include, but are not limited to, diethylene glycol methylether, dipropylene glycol methyl ether, 2-butoxy ethanol, ethers of a C2to C6 dihydric alkanol containing at least one C1 to C6 alkyl group,mono ethers of dihydric alkanols, methoxypropanol, butoxyethanol, andhexoxyethanol, and isomers thereof. Selection of an appropriate solventis dependent on the resin composition chosen and is within the abilityof one skilled in the art, with the benefit of this disclosure.

As described above, use of a solvent in the liquid hardenable resincomponent is optional but may be desirable to reduce the viscosity ofthe hardenable resin component for ease of handling, mixing, andtransferring. However, as previously stated, it may be desirable in someembodiments to not use such a solvent for environmental or safetyreasons. It is within the ability of one skilled in the art, with thebenefit of this disclosure, to determine if and how much solvent isneeded to achieve a suitable viscosity. In some embodiments, the amountof the solvent used in the liquid hardenable resin component may be inthe range of about 0.1% to about 30% by weight of the liquid hardenableresin component. Optionally, the liquid hardenable resin component maybe heated to reduce its viscosity, in place of, or in addition to, usinga solvent.

Examples of the hardening agents that can be used in the liquidhardening agent component include, but are not limited to,cycloaliphatic amines, such as piperazine, derivatives of piperazine(e.g., aminoethylpiperazine) and modified piperazines; aromatic amines,such as methylene dianiline, derivatives of methylene dianiline andhydrogenated forms, and 4,4′-diaminodiphenyl sulfone; aliphatic amines,such as ethylene diamine, diethylene triamine, triethylene tetraamine,and tetraethylene pentaamine; imidazole; pyrazole; pyrazine; pyrimidine;pyridazine; 1H-indazole; purine; phthalazine; naphthyridine;quinoxaline; quinazoline; phenazine; imidazolidine; cinnoline;imidazoline; 1,3,5-triazine; thiazole; pteridine; indazole; amines;polyamines; amides; polyamides; and 2-ethyl-4-methyl imidazole; andcombinations thereof. The chosen hardening agent often effects the rangeof temperatures over which a hardenable resin is able to cure. By way ofexample, and not of limitation, in subterranean formations having atemperature of about 60° F. to about 250° F., amines and cyclo-aliphaticamines such as piperidine, triethylamine,tris(dimethylaminomethyl)phenol, and dimethylaminomethyl)phenol may bepreferred. In subterranean formations having higher temperatures,4,4′-diaminodiphenyl sulfone may be a suitable hardening agent.Hardening agents that comprise piperazine or a derivative of piperazinehave been shown capable of curing various hardenable resins fromtemperatures as low as about 50° F. to as high as about 350° F.

The hardening agent used may be included in the liquid hardening agentcomponent in an amount sufficient to at least partially harden the resincomposition. In some embodiments of the present invention, the hardeningagent used is included in the liquid hardening agent component in therange of about 0.1% to about 95% by weight of the liquid hardening agentcomponent. In other embodiments, the hardening agent used may beincluded in the liquid hardening agent component in an amount of about15% to about 85% by weight of the liquid hardening agent component. Inother embodiments, the hardening agent used may be included in theliquid hardening agent component in an amount of about 15% to about 55%by weight of the liquid hardening agent component.

In some embodiments, the consolidating agent may comprise a liquidhardenable resin component emulsified in a liquid hardening agentcomponent, wherein the liquid hardenable resin component is the internalphase of the emulsion and the liquid hardening agent component is theexternal phase of the emulsion. In other embodiments, the liquidhardenable resin component may be emulsified in water and the liquidhardening agent component may be present in the water. In otherembodiments, the liquid hardenable resin component may be emulsified inwater and the liquid hardening agent component may be providedseparately. Similarly, in other embodiments, both the liquid hardenableresin component and the liquid hardening agent component may both beemulsified in water.

The optional silane coupling agent may be used, among other things, toact as a mediator to help bond the resin to particulates. Examples ofsuitable silane coupling agents include, but are not limited to,N-2-(aminoethyl)-3-aminopropyltrimethoxysilane, and3-glycidoxypropyltrimethoxysilane, and combinations thereof. The silanecoupling agent may be included in the resin component or the liquidhardening agent component (according to the chemistry of the particulargroup as determined by one skilled in the art with the benefit of thisdisclosure). In some embodiments of the present invention, the silanecoupling agent used is included in the liquid hardening agent componentin the range of about 0.1% to about 3% by weight of the liquid hardeningagent component.

Any surfactant compatible with the hardening agent and capable offacilitating the coating of the resin onto particulates in thesubterranean formation may be used in the liquid hardening agentcomponent. Such surfactants include, but are not limited to, an alkylphosphonate surfactant (e.g., a C12-C22 alkyl phosphonate surfactant),an ethoxylated nonyl phenol phosphate ester, one or more cationicsurfactants, and one or more nonionic surfactants. Combinations of oneor more cationic and nonionic surfactants also may be suitable. Examplesof such surfactant combinations are described in U.S. Pat. No.6,311,773, the relevant disclosure of which is incorporated herein byreference. The surfactant or surfactants that may be used are includedin the liquid hardening agent component in an amount in the range ofabout 1% to about 10% by weight of the liquid hardening agent component.

While not required, examples of hydrolyzable esters that may be used inthe liquid hardening agent component include, but are not limited to, acombination of dimethylglutarate, dimethyladipate, anddimethylsuccinate; dimethylthiolate; methyl salicylate; dimethylsalicylate; and dimethylsuccinate; and combinations thereof. When used,a hydrolyzable ester is included in the liquid hardening agent componentin an amount in the range of about 0.1% to about/by weight of the liquidhardening agent component. In some embodiments a hydrolyzable ester isincluded in the liquid hardening agent component in an amount in therange of about 1% to about 2.5% by weight of the liquid hardening agentcomponent.

Use of a diluent or liquid carrier fluid in the liquid hardening agentcomponent is optional and may be used to reduce the viscosity of theliquid hardening agent component for ease of handling, mixing, andtransferring. As previously stated, it may be desirable in someembodiments to not use such a solvent for environmental or safetyreasons. Any suitable carrier fluid that is compatible with the liquidhardening agent component and achieves the desired viscosity effects issuitable for use in the present invention. Some suitable liquid carrierfluids are those having high flash points (e.g., about 125° F.) becauseof, among other things, environmental and safety concerns; such solventsinclude, but are not limited to, butyl lactate, dipropylene glycolmethyl ether, dipropylene glycol dimethyl ether, dimethyl formamide,diethyleneglycol methyl ether, ethyleneglycol butyl ether,diethyleneglycol butyl ether, propylene carbonate, methanol, butylalcohol, d'limonene, and fatty acid methyl esters, and combinationsthereof. Other suitable liquid carrier fluids include aqueousdissolvable solvents such as, for example, methanol, isopropanol,butanol, glycol ether solvents, and combinations thereof. Suitableglycol ether liquid carrier fluids include, but are not limited to,diethylene glycol methyl ether, dipropylene glycol methyl ether,2-butoxy ethanol, ethers of a C2 to C6 dihydric alkanol having at leastone C1 to C6 alkyl group, mono ethers of dihydric alkanols,methoxypropanol, butoxyethanol, and hexoxyethanol, and isomers thereof.Combinations of these may be suitable as well. Selection of anappropriate liquid carrier fluid is dependent on, inter alia, the resincomposition chosen.

Other resins suitable for use in the present invention are furan-basedresins. Suitable furan-based resins include, but are not limited to,furfuryl alcohol resins, furfural resins, combinations of furfurylalcohol resins and aldehydes, and a combination of furan resins andphenolic resins. Of these, furfuryl alcohol resins may be preferred. Afuran-based resin may be combined with a solvent to control viscosity ifdesired. Suitable solvents for use in the furan-based consolidationfluids of the present invention include, but are not limited to,2-butoxy ethanol, butyl lactate, butyl acetate, tetrahydrofurfurylmethacrylate, tetrahydrofurfuryl acrylate, esters of oxalic, maleic andsuccinic acids, and furfuryl acetate. Of these, 2-butoxy ethanol ispreferred. In some embodiments, the furan-based resins suitable for usein the present invention may be capable of enduring temperatures well inexcess of 350° F. without degrading. In some embodiments, thefuran-based resins suitable for use in the present invention are capableof enduring temperatures up to about 700° F. without degrading.

Optionally, the furan-based resins suitable for use in the presentinvention may further comprise a curing agent to facilitate oraccelerate curing of the furan-based resin at lower temperatures. Thepresence of a curing agent may be particularly useful in embodimentswhere the furan-based resin may be placed within subterranean formationshaving temperatures below about 350° F. Examples of suitable curingagents include, but are not limited to, organic or inorganic acids, suchas, inter alia, maleic acid, fumaric acid, sodium bisulfate,hydrochloric acid, hydrofluoric acid, acetic acid, formic acid,phosphoric acid, sulfonic acid, alkyl benzene sulfonic acids such astoluene sulfonic acid and dodecyl benzene sulfonic acid (“DDBSA”), andcombinations thereof. In those embodiments where a curing agent is notused, the furan-based resin may cure autocatalytically.

Still other resins suitable for use in the methods of the presentinvention are phenolic-based resins. Suitable phenolic-based resinsinclude, but are not limited to, terpolymers of phenol, phenolicformaldehyde resins, and a combination of phenolic and furan resins. Insome embodiments, a combination of phenolic and furan resins may bepreferred. A phenolic-based resin may be combined with a solvent tocontrol viscosity if desired. Suitable solvents for use in the presentinvention include, but are not limited to, butyl acetate, butyl lactate,furfuryl acetate, and 2-butoxy ethanol. Of these, 2-butoxy ethanol maybe preferred in some embodiments,

Yet another resin-type material suitable for use in the methods of thepresent invention is a phenol/phenol formaldehyde/furfuryl alcohol resincomprising of about 5% to about 30% phenol, of about 40% to about 70%phenol formaldehyde, of about 10% to about 40% furfuryl alcohol, ofabout 0.1% to about 3% of a silane coupling agent, and of about 1% toabout 15% of a surfactant. In the phenol/phenol formaldehyde/furfurylalcohol resins suitable for use in the methods of the present invention,suitable silane coupling agents include, but are not limited to,N-2-(aminoethyl)-3-aminopropyltrimethoxysilane, and3-glycidoxypropyltrimethoxysilane. Suitable surfactants include, but arenot limited to, an ethoxylated nonyl phenol phosphate ester,combinations of one or more cationic surfactants, and one or morenonionic surfactants and an alkyl phosphonate surfactant.

In some embodiments, resins suitable for use in the consolidating agentemulsion compositions of the present invention may optionally comprisefiller particles. Suitable filler particles may include any particlethat does not adversely react with the other components used inaccordance with this invention or with the subterranean formation.Examples of suitable filler particles include silica, glass, clay,alumina, fumed silica, carbon black, graphite, mica, meta-silicate,calcium silicate, calcine, kaoline, talc, zirconia, titanium dioxide,fly ash, and boron, and combinations thereof. In some embodiments, thefiller particles may range in size of about 0.01 μm to about 100 μm. Aswill be understood by one skilled in the art, particles of smalleraverage size may be particularly useful in situations where it isdesirable to obtain high proppant pack permeability (i.e.,conductivity), and/or high consolidation strength. In certainembodiments, the filler particles may be included in the resincomposition in an amount of about 0.1% to about 70% by weight of theresin composition. In other embodiments, the filler particles may beincluded in the resin composition in an amount of about 0.5% to about40% by weight of the resin composition. In some embodiments, the fillerparticles may be included in the resin composition in an amount of about1% to about 10% by weight of the resin composition. Some examples ofsuitable resin compositions comprising filler particles are described inU.S. Patent Publication Number 2008/0006405, the entire disclosure ofwhich is herein incorporated by reference.

Silyl-modified polyamide compounds may be described as substantiallyself-hardening compositions that are capable of at least partiallyadhering to particulates in the unhardened state, and that are furthercapable of self-hardening themselves to a substantially non-tacky stateto which individual particulates such as formation fines will not adhereto, for example, in formation or proppant pack pore throats. Suchsilyl-modified polyamides may be based, for example, on the reactionproduct of a silating compound with a polyamide or a combination ofpolyamides. The polyamide or combination of polyamides may be one ormore polyamide intermediate compounds obtained, for example, from thereaction of a polyacid (e.g., diacid or higher) with a polyamine (e.g.,diamine or higher) to form a polyamide polymer with the elimination ofwater. Other suitable silyl-modified polyamides and methods of makingsuch compounds are described in U.S. Pat. No. 6,439,309, the relevantdisclosure of which is herein incorporated by reference.

In other embodiments, the consolidating agent comprises crosslinkableaqueous polymer compositions. Generally, suitable crosslinkable aqueouspolymer compositions comprise an aqueous solvent, a crosslinkablepolymer, and a crosslinking agent. Such compositions are similar tothose used to form gelled treatment fluids, such as fracturing fluids,but according to the methods of the present invention, they are notexposed to breakers or de-linkers, and so they retain their viscousnature over time. The aqueous solvent may be any aqueous solvent inwhich the crosslinkable composition and the crosslinking agent may bedissolved, mixed, suspended, or dispersed therein to facilitate gelformation. For example, the aqueous solvent used may be freshwater, saltwater, brine, seawater, or any other aqueous liquid that does notadversely react with the other components used in accordance with thisinvention or with the subterranean formation.

Examples of crosslinkable polymers that can be used in the crosslinkableaqueous polymer compositions include, but are not limited to,carboxylate-containing polymers and acrylamide-containing polymers. Themost suitable polymers are thought to be those that would absorb oradhere to the rock surfaces so that the rock matrix may be strengthenedwithout occupying a lot of the pore space and/or reducing permeability.Examples of suitable acrylamide-containing polymers includepolyacrylamide, partially hydrolyzed polyacrylamide, copolymers ofacrylamide and acrylate, and carboxylate-containing terpolymers andtetrapolymers of acrylate. Combinations of these may be suitable aswell. Additional examples of suitable crosslinkable polymers includehydratable polymers comprising polysaccharides and derivatives thereof,and that contain one or more of the monosaccharide units, galactose,mannose, glucoside, glucose, xylose, arabinose, fructose, glucuronicacid, or pyranosyl sulfate. Suitable natural hydratable polymersinclude, but are not limited to, guar gum, locust bean gum, tara,konjak, tamarind, starch, cellulose, karaya, xanthan, tragacanth, andcarrageenan, and derivatives of all of the above. Combinations of thesemay be suitable as well. Suitable hydratable synthetic polymers andcopolymers that may be used in the crosslinkable aqueous polymercompositions include, but are not limited to, polycarboxylates such aspolyacrylates and polymethacrylates; polyacrylamides; methylvinyl etherpolymers; polyvinyl alcohols; and polyvinylpyrrolidone. Combinations ofthese may be suitable as well. The crosslinkable polymer used should beincluded in the crosslinkable aqueous polymer composition in an amountsufficient to form the desired gelled substance in the subterraneanformation. In some embodiments of the present invention, thecrosslinkable polymer may be included in the crosslinkable aqueouspolymer composition in an amount in the range of from about 1% to about30% by weight of the aqueous solvent. In another embodiment of thepresent invention, the crosslinkable polymer may be included in thecrosslinkable aqueous polymer composition in an amount in the range offrom about 1% to about 20% by weight of the aqueous solvent.

The crosslinkable aqueous polymer compositions of the present inventionfurther comprise a crosslinking agent for crosslinking the crosslinkablepolymers to form the desired gelled substance. In some embodiments, thecrosslinking agent is a molecule or complex containing a reactivetransition metal cation. A most preferred crosslinking agent comprisestrivalent chromium cations complexed or bonded to anions, atomic oxygen,or water. Examples of suitable crosslinking agents include, but are notlimited to, compounds or complexes containing chromic acetate and/orchromic chloride. Other suitable transition metal cations includechromium VI within a redox system, aluminum III, iron II, iron III, andzirconium IV.

The crosslinking agent should be present in the crosslinkable aqueouspolymer compositions of the present invention in an amount sufficient toprovide, among other things, the desired degree of crosslinking. In someembodiments of the present invention, the crosslinking agent may bepresent in the crosslinkable aqueous polymer compositions of the presentinvention in an amount in the range of from about 0.1% to about 5% byweight of the crosslinkable aqueous polymer composition. The exact typeand amount of crosslinking agent or agents used depends upon thespecific crosslinkable polymer to be crosslinked, formation temperatureconditions, and other factors known to those individuals skilled in theart.

Optionally, the crosslinkable aqueous polymer compositions may furthercomprise a crosslinking delaying agent, such as a polysaccharidecrosslinking delaying agent derived from guar, guar derivatives, orcellulose derivatives. The crosslinking delaying agent may be includedin the crosslinkable aqueous polymer compositions, among other things,to delay crosslinking of the crosslinkable aqueous polymer compositionsuntil desired. One of ordinary skill in the art, with the benefit ofthis disclosure, will know the appropriate amount of the crosslinkingdelaying agent to include in the crosslinkable aqueous polymercompositions for a desired application.

In other embodiments, the consolidating agents useful in the methods ofthe present invention comprise polymerizable organic monomercompositions. Generally, suitable polymerizable organic monomercompositions comprise an aqueous-base fluid, a water-solublepolymerizable organic monomer, an oxygen scavenger, and a primaryinitiator.

The aqueous-based fluid component of the polymerizable organic monomercomposition generally may be freshwater, salt water, brine, seawater, orany other aqueous liquid that does not adversely react with the othercomponents used in accordance with this invention or with thesubterranean formation.

A variety of monomers are suitable for use as the water-solublepolymerizable organic monomers in the present invention. Examples ofsuitable monomers include, but are not limited to, acrylic acid,methacrylic acid, acrylamide, methacrylamide,2-methacrylamido-2-methylpropane sulfonic acid, dirnethylacrylamide,vinyl sulfonic acid, N,N-dimethylaminoethylmethacrylate,2-triethylammoniumethylmethacrylate chloride,N,N-dimethyl-aminopropylmethacryl-amide,methacrylamidepropyltriethylammonium chloride, N-vinyl pyrrolidone,vinyl-phosphonic acid, and methacryloyloxyethyl trimethylammoniumsulfate, and combinations thereof. In some embodiments, thewater-soluble polymerizable organic monomer should be self-crosslinking.Examples of suitable monomers which are thought to be self crosslinkinginclude, but are not limited to, hydroxyethylacrylate,hydroxymethylacrylate, hydroxyethylmethacrylate,N-hydroxymethylacrylamide, N-hydroxymethyl-methacrylamide, polyethyleneglycol acrylate, polyethylene glycol methacrylate, polypropylene gylcolacrylate, and polypropylene glycol methacrylate, and combinationsthereof. Of these, hydroxyethylacrylate may be preferred in someinstances. An example of a particularly suitable monomer ishydroxyethylcellulose-vinyl phosphoric acid. The water-solublepolymerizable organic monomer (or monomers where a combination thereofis used) should be included in the polymerizable organic monomercomposition in an amount sufficient to form the desired gelled substanceafter placement of the polymerizable organic monomer composition intothe subterranean formation. In some embodiments of the presentinvention, the water-soluble polymerizable organic monomer may beincluded in the polymerizable organic monomer composition in an amountin the range of from about 1% to about 30% by weight of the aqueous-basefluid. In another embodiment of the present invention, the water-solublepolymerizable organic monomer may be included in the polymerizableorganic monomer composition in an amount in the range of from about 1%to about 20% by weight of the aqueous-base fluid.

The presence of oxygen in the polymerizable organic monomer compositionmay inhibit the polymerization process of the water-solublepolymerizable organic monomer or monomers. Therefore, an oxygenscavenger, such as stannous chloride, may be included in thepolymerizable monomer composition. In order to improve the solubility ofstannous chloride so that it may be readily combined with thepolymerizable organic monomer composition on the fly, the stannouschloride may be predissolved in a hydrochloric acid solution. Forexample, the stannous chloride may be dissolved in a 0.1% by weightaqueous hydrochloric acid solution in an amount of about 10% by weightof the resulting solution. The resulting stannous chloride-hydrochloricacid solution may be included in the polymerizable organic monomercomposition in an amount in the range of from about 0.1% to about 10% byweight of the polymerizable organic monomer composition. Generally, thestannous chloride may be included in the polymerizable organic monomercomposition of the present invention in an amount in the range of fromabout 0.005% to about 0.1% by weight of the polymerizable organicmonomer composition.

A primary initiator may be used, among other things, to initiatepolymerization of the water-soluble polymerizable organic monomer(s).Any compound or compounds that form free radicals in aqueous solutionmay be used as the primary initiator. The free radicals act, among otherthings, to initiate polymerization of the water-soluble polymerizableorganic monomer present in the polymerizable organic monomercomposition. Compounds suitable for use as the primary initiatorinclude, but are not limited to, alkali metal persulfates; peroxides;oxidation-reduction systems employing reducing agents, such as sulfitesin combination with oxidizers; and azo polymerization initiators.Suitable azo polymerization initiators include2,2′-azobis(2-imidazole-2-hydroxyethyl)propane,2,2′-azobis(2-aminopropane), 4,4′-azobis(4-cyanovaleric acid), and2,2′-azobis(2-methyl-N-(2-hydroxyethyl)propionamide. Generally, theprimary initiator should be present in the polymerizable organic monomercomposition in an amount sufficient to initiate polymerization of thewater-soluble polymerizable organic monomer(s). In certain embodimentsof the present invention, the primary initiator may be present in thepolymerizable organic monomer composition in an amount in the range offrom about 0.1% to about 5% by weight of the water-soluble polymerizableorganic monomer(s). One skilled in the art, with the benefit of thisdisclosure, will recognize that as the polymerization temperatureincreases, the required level of activator decreases.

Optionally, the polymerizable organic monomer compositions further maycomprise a secondary initiator. A secondary initiator may be used, forexample, where the immature aqueous gel is placed into a subterraneanformation that is relatively cool as compared to the surface mixing,such as when placed below the mud line in offshore operations. Thesecondary initiator may be any suitable water-soluble compound orcompounds that may react with the primary initiator to provide freeradicals at a lower temperature. An example of a suitable secondaryinitiator is triethanolamine. In some embodiments of the presentinvention, the secondary initiator is present in the polymerizableorganic monomer composition in an amount in the range of from about 0.1%to about 5% by weight of the water-soluble polymerizable organicmonomer(s).

Also optionally, the polymerizable organic monomer compositions of thepresent invention may further comprise a crosslinking agent forcrosslinking the polymerizable organic monomer compositions in thedesired gelled substance. In some embodiments, the crosslinking agent isa molecule or complex containing a reactive transition metal cation. Asuitable crosslinking agent comprises trivalent chromium cationscomplexed or bonded to anions, atomic oxygen, or water. Examples ofsuitable crosslinking agents include, but are not limited to, compoundsor complexes containing chromic acetate and/or chromic chloride. Othersuitable transition metal cations include chromium VI within a redoxsystem, aluminum III, iron II, iron III, and zirconium IV. Generally,the crosslinking agent may be present in polymerizable organic monomercompositions in an amount in the range of from 0.01% to about 5% byweight of the polymerizable organic monomer composition.

In some embodiments, a treatment fluid may comprise a base fluidselected from an oil-based fluid, an aqueous-based fluid, a water-in-oilemulsion, or an oil-in-water emulsion. In some embodiments, the basefluid may vary for the different steps described above. In suchembodiments, one skilled in the art should understand that a pill mayoptionally need to be inserted between steps to properly change basefluids.

Suitable oil-based fluids may include an alkane, an olefin, an aromaticorganic compound, a cyclic alkane, a paraffin, a diesel fluid, a mineraloil, a desulfurized hydrogenated kerosene, and any combination thereof.Examples of suitable invert emulsions include those disclosed in U.S.Pat. No. 5,905,061 5,977,031; and 6,828,279, each of which areincorporated herein by reference. Aqueous base fluids suitable for usein the treatment fluids of the present invention may comprise freshwater, saltwater (e.g., water containing one or more salts dissolvedtherein), brine (e.g. saturated salt water), seawater, or combinationsthereof. Generally, the water may be from any source, provided that itdoes not contain components that might adversely affect the stabilityand/or performance of the first treatment fluids or second treatmentfluids of the present invention. In certain embodiments, the density ofthe aqueous base fluid can be adjusted, among other purposes, to provideadditional particulate transport and suspension in the treatment fluidsused in the methods of the present invention. In certain embodiments,the pH of the aqueous base fluid may be adjusted (e.g., by a buffer orother pH adjusting agent), among other purposes, to activate acrosslinking agent and/or to reduce the viscosity of the first treatmentfluid (e.g., activate a breaker, deactivate a crosslinking agent). Inthese embodiments, the pH may be adjusted to a specific level, which maydepend on, among other factors, the types of gelling agents, acids, andother additives included in the treatment fluid. One of ordinary skillin the art, with the benefit of this disclosure, will recognize whensuch density and/or pH adjustments are appropriate.

In some embodiments, a treatment fluid for use in the present inventionmay further comprise an additive including, but not limited to, a salt;a weighting agent; an inert solid; a fluid loss control agent; anemulsifier; a dispersion aid; a corrosion inhibitor; an emulsionthinner; an emulsion thickener; a viscosifying agent; a high-pressure,high-temperature emulsifier-filtration control agent; a surfactant; aparticulate; a lost circulation material; a foaming agent; a gas; a pHcontrol additive; a breaker; a biocide; a crosslinker; a stabilizer; achelating agent; a scale inhibitor; a mutual solvent; an oxidizer; areducer; a friction reducer; a clay stabilizing agent; and anycombination thereof.

In some embodiments, the present invention provides for of treating asubterranean formation able to support a fracture network having atleast one access conduit to the subterranean formation from a wellbore.Treating the subterranean formation may include the steps, notnecessarily in this order or performed independently, placing a firsttreatment fluid into the subterranean formation through the at least oneaccess conduit at a pressure sufficient to form at least a portion of afracture network extending from the at least one access conduit; pumpinga second treatment fluid comprising a propping agent into the fracturenetwork such that the propping agent forms a proppant pack in at least aportion of the fracture network; placing a third treatment fluidcomprising a secondary diverting agent into the wellbore such that thesecondary diverting agent goes through the access conduit and into atleast a portion of the fracture network so as to substantially inhibitfluid flow through at least a portion of the fracture network withoutsubstantially inhibiting fluid flow through the access conduit; andplacing a fourth treatment fluid comprising a primary diverting agentinto the wellbore such that the primary diverting agent substantiallyinhibits fluid flow through the access conduit.

In some embodiments, the present invention provides for of treating asubterranean formation having a closure pressure greater than about 500psi and having at least one access conduit to the subterranean formationfrom a wellbore. Treating the subterranean formation may include thesteps, not necessarily in this order or performed independently, placinga first treatment fluid into the subterranean formation through the atleast one access conduit at a pressure sufficient to form at least aportion of a fracture network extending from the at least one accessconduit; pumping a second treatment fluid comprising a propping agentinto the fracture network such that the propping agent forms a proppantpack in at least a portion of the fracture network; placing a thirdtreatment fluid comprising a secondary diverting agent into the wellboresuch that the secondary diverting agent goes through the access conduitand into at least a portion of the fracture network so as tosubstantially inhibit fluid flow through at least a portion of thefracture network without substantially inhibiting fluid flow through theaccess conduit; and placing a fourth treatment fluid comprising aprimary diverting agent into the wellbore such that the primarydiverting agent substantially inhibits fluid flow through the accessconduit.

In some embodiments, the present invention provides for of treating asubterranean formation able to support a fracture network having atleast one access conduit to the subterranean formation from a wellbore.Treating the subterranean formation may include the steps, notnecessarily in this order or performed independently, placing a firsttreatment fluid into the subterranean formation at a pressure sufficientto form at least a portion of a fracture network extending from at leastone access conduit; pumping a second treatment fluid comprising apropping agent into the fracture network such that the propping agentforms a proppant pack in at least a portion of the fracture network,wherein the propping agent comprises proppant particulates at leastpartially coated with a consolidating agent and at least a portion ofdegradable particles; placing a third treatment fluid comprising asecondary diverting agent into the wellbore such that the secondarydiverting agent goes through the access conduit and into at least aportion of the fracture network so as to substantially inhibit fluidflow through at least a portion of the fracture network withoutsubstantially inhibiting fluid flow through the access conduit, whereinthe secondary diverting agent is at least partially degradable; placinga fourth treatment fluid comprising a primary diverting agent into thewellbore such that the primary diverting agent substantially inhibitsfluid flow through the access conduit, wherein the primary divertingagent is at least partially degradable; and repeating at least one stepselected from the group consisting of pumping the second treatmentfluid, placing the third treatment fluid, placing the fourth treatmentfluid, placing the fifth treatment fluid, and any combination thereof.

To facilitate a better understanding of the present invention, thefollowing examples of preferred embodiments are given. In no way shouldthe following examples be read to limit, or to define, the scope of theinvention.

Therefore, the present invention is well adapted to attain the ends andadvantages mentioned as well as those that are inherent therein. Theparticular embodiments disclosed above are illustrative only, as thepresent invention may be modified and practiced in different butequivalent manners apparent to those skilled in the art having thebenefit of the teachings herein. Furthermore, no limitations areintended to the details of construction or design herein shown, otherthan as described in the claims below. It is therefore evident that theparticular illustrative embodiments disclosed above may be altered,combined, or modified and all such variations are considered within thescope and spirit of the present invention. The invention illustrativelydisclosed herein suitably may be practiced in the absence of any elementwhich is not specifically disclosed herein. While compositions andmethods are described in terms of “comprising,” “containing,” or“including” various components or steps, the compositions and methodscan also “consist essentially of” or “consist of” the various componentsand steps. All numbers and ranges disclosed above may vary by someamount. Whenever a numerical range with a lower limit and an upper limitis disclosed, any number and any included range falling within the rangeis specifically disclosed. In particular, every range of values (of theform, “from about a to about b,” or, equivalently, “from approximately ato b,” or, equivalently, “from approximately a-b”) disclosed herein isto be understood to set forth every number and range encompassed withinthe broader range of values. Also, the terms in the claims have theirplain, ordinary meaning unless otherwise explicitly and clearly definedby the patentee. Moreover, the indefinite articles “a” or “an,” as usedin the claims, are defined herein to mean one or more than one of theelement that it introduces. If there is any conflict in the usages of aword or term in this specification and one or more patent or otherdocuments that may be incorporated herein by reference, the definitionsthat are consistent with this specification should be adopted.

1. A method comprising: providing a wellbore penetrating a subterraneanformation, wherein the subterranean formation is able to support afracture network; providing at least one access conduit to thesubterranean formation from the wellbore; placing a first treatmentfluid into the subterranean formation through at least one accessconduit at a pressure sufficient to form at least a portion of afracture network extending from at least one access conduit; pumping asecond treatment fluid comprising a propping agent into the fracturenetwork such that the propping agent forms a proppant pack in at least aportion of the fracture network; placing a third treatment fluidcomprising a secondary diverting agent into the wellbore such that thesecondary diverting agent goes through the access conduit and into atleast a portion of the fracture network so as to substantially inhibitfluid flow through at least a portion of the fracture network withoutsubstantially inhibiting fluid flow through the access conduit; andplacing a fourth treatment fluid comprising a primary diverting agentinto the wellbore such that the primary diverting agent substantiallyinhibits fluid flow through the access conduit.
 2. The method of claim 1further comprising: producing hydrocarbons from the subterraneanformation.
 3. The method of claim 1, wherein pumping the secondtreatment fluid, placing the third treatment fluid, and placing thefourth treatment fluid are performed in any order.
 4. The method ofclaim 1, wherein pumping the second treatment fluid is done continuouslywhile placing the third treatment fluid and placing the fourth treatmentfluid.
 5. The method of claim 1, wherein the concentration of thepropping agent in the second treatment fluid is changed during pumping.6. The method of claim 1, wherein a step selected from the groupconsisting of pumping the second treatment fluid, placing the thirdtreatment fluid, placing the fourth treatment fluid, and any combinationthereof are performed more than once.
 7. The method of claim 1, whereinthe first treatment fluid, the second treatment fluid, the thirdtreatment fluid, and the fourth treatment fluid comprise the same basefluid with different additives.
 8. The method of claim 1, wherein thepropping agent comprises a proppant particulate coated with aconsolidating agent.
 9. The method of claim 1, wherein the secondarydiverting agent has a diameter of about 150 microns or less.
 10. Themethod of claim 1, wherein the secondary diverting agent is at leastpartially degradable,
 11. The method of claim 1, wherein the primarydiverting agent has a bimodal particle size distribution.
 12. The methodof claim 1, wherein the primary diverting agent comprises firstparticulates, wherein the secondary diverting agent comprises secondparticles, and wherein the first particles have a larger averagediameter than the second particulates.
 13. The method of claim 1,wherein the primary diverting agent comprises perf balls.
 14. The methodof claim 1, wherein the primary diverting agent comprises a gel.
 15. Themethod of claim 1, wherein the primary diverting agent is at leastpartially degradable.
 16. The method of claim 1 further comprising:introducing a cleanup treatment fluid into the wellbore to enhance fluidflow through at least a portion of the fracture network.
 17. The methodof claim 1 further comprising: placing a fifth treatment fluidcomprising a degradable particle into the fracture network such that thedegradable particle is capable of forming voids within at least aportion of the proppant pack.
 18. The method of claim 17, whereinplacing a fifth treatment fluid and pumping a second treatment fluid areperformed simultaneously.
 19. The method of claim 17, wherein the fifthtreatment fluid further comprises the propping agent.
 20. The method ofclaim 17 further comprising: introducing a cleanup treatment fluid intothe wellbore to enhance fluid flow through at least a portion of thefracture network.
 21. The method of claim 17, wherein a step selectedfrom the group consisting of pumping the second treatment fluid, placingthe third treatment fluid, placing the fourth treatment fluid, placing afifth treatment fluid, and any combination thereof is performed morethan once.
 22. A method comprising: providing a wellbore penetrating asubterranean formation, wherein the subterranean formation has a closurepressure greater than about 500 psi; providing at least one accessconduit to the subterranean formation from the wellbore; placing a firsttreatment fluid into the subterranean formation through the at least oneaccess conduit at a pressure sufficient to form at least a portion of afracture network extending from the at least one access conduit; pumpinga second treatment fluid comprising a propping agent into the fracturenetwork such that the propping agent forms a proppant pack in at least aportion of the fracture network; placing a third treatment fluidcomprising a secondary diverting agent into the wellbore such that thesecondary diverting agent goes through the access conduit and into atleast a portion of the fracture network so as to substantially inhibitfluid flow through at least a portion of the fracture network withoutsubstantially inhibiting fluid flow through the access conduit; andplacing a fourth treatment fluid comprising a primary diverting agentinto the wellbore such that the primary diverting agent substantiallyinhibits fluid flow through the access conduit.
 23. A method comprising:providing a wellbore penetrating a subterranean formation, wherein thesubterranean formation is able to support a fracture network and thewellbore has at least one access conduit to the subterranean formationfrom the wellbore; placing a first treatment fluid into the subterraneanformation at a pressure sufficient to form at least a portion of afracture network extending from at least one access conduit; pumping asecond treatment fluid comprising a propping agent into the fracturenetwork such that the propping agent forms a proppant pack in at least aportion of the fracture network, wherein the propping agent comprisesproppant particulates at least partially coated with a consolidatingagent and at least a portion of degradable particles; placing a thirdtreatment fluid comprising a secondary diverting agent into the wellboresuch that the secondary diverting agent goes through the access conduitand into at least a portion of the fracture network so as tosubstantially inhibit fluid flow through at least a portion of thefracture network without substantially inhibiting fluid flow through theaccess conduit, wherein the secondary diverting agent is at leastpartially degradable; placing a fourth treatment fluid comprising aprimary diverting agent into the wellbore such that the primarydiverting agent substantially inhibits fluid flow through the accessconduit, wherein the primary diverting agent is at least partiallydegradable; and repeating at least one step selected from the groupconsisting of pumping the second treatment fluid, placing the thirdtreatment fluid, placing the fourth treatment fluid, placing the fifthtreatment fluid, and any combination thereof.